Compositions and Methods for Pressure Protection

ABSTRACT

Disclosed are compositions and methods for the pressure protection of existing wells during infill drilling operations.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority to 62/871,164 filed Jul.7, 2019, 62/873,901 filed Jul. 13, 2019, 62/871,165 filed Jul. 7, 2019,62/873,904 filed Jul. 13, 2019, and 62/873,902 filed Jul. 13, 2019, andeach of these disclosures is incorporated by reference herein in itsentirety.

BACKGROUND

During hydraulic fracturing operations in shale and tight rockreservoirs, new wells drilled adjacent (e.g., within 5000 ft) toexisting or parent wells can produce sub-optimal results due towell-to-well interference. For example, the fracture network for the new(child) well can be skewed towards the existing (parent or teenage)well, resulting in a negative production impact to the child well. Therecan also be a premature decline in production in the existing well wherethe fracturing treatment in the new well pushes fluids and debris (e.g.,sand, shale fragments) into the existing well, potentially causingdamage to the completion or lift equipment of the existing well and/orrequiring the existing well to be shut-in or cleaned out. This loss ofproduction and poor fracture alignment is well documented in literatureand industry.

SUMMARY

During infill drilling, water can be pumped into the existing wells toincrease wellbore pressure. This injection can help the child wellfracture network be less skewed and limit the amount of fluid/debrisintroduced into the existing well(s) during the fracturing operation onthe child well. This approach can be referred to as frac protect, activewell defense, pre-loading, loading, or recharging.

Herein, methods which employ aqueous pressure protection compositionsare described. The aqueous pressure protection compositions can includeone or more components which can improve hydrocarbon recovery from theexisting wellbore (e.g., following pressure protection/pre-loading withthe aqueous pressure protection composition). Examples of suchcomponents include a surfactant package, an acid (e.g., to improvepermeability in proximity to the wellbore and/or to remove any mineralprecipitates in proximity to the wellbore), an alkali agent (e.g., toreduce surfactant adsorption and/or to generate surfactant in situ fromactive oils present in the formation), a co-solvent, aviscosity-modifying polymer, or any combination thereof. Additionaladditives can also be incorporated in the aqueous pressure protectioncompositions, such as a chelating agent (e.g., EDTA or a salt thereof,to reduce formation damage), a clay swelling inhibitor (e.g., KCl, toimprove injection efficiency), a biocide, a scale inhibitor, ananti-foam agent (e.g., chemical defoamer), a corrosion inhibitor, or anycombination thereof.

Provided are methods for the pressure protection of wells (e.g., bypre-loading the wells) using the aqueous pressure protectioncompositions described herein. Methods for the pressure protection of anexisting wellbore that has previously been fractured in proximity to anew wellbore to be fractured can comprise (a) injecting an aqueouspressure protection composition into the unconventional subterraneanformation via an existing wellbore in fluid communication with a rockmatrix of the unconventional subterranean formation prior to and/orduring injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. The aqueous pressure protection solution canbe injected at a pressure and flowrate effective to increase theexisting wellbore pressure without substantially refracturing theexisting wellbore.

Also provided are methods for pressure protection of a first wellbore inproximity to a second wellbore. These methods can comprise injecting anaqueous pressure protection composition into the first wellbore in fluidcommunication with an unconventional subterranean formation prior toand/or during fracturing of the second wellbore in fluid communicationwith the unconventional subterranean formation. The first wellbore canhave an existing reservoir pressure that is less than original reservoirpressure. The aqueous pressure protection solution can be injected at apressure and flowrate effective to increase the first wellbore pressurewithout fracturing the first wellbore. The aqueous pressure protectionsolution can include a surfactant package including a first surfactant.A region of the unconventional subterranean formation in fluidcommunication with the first wellbore can be naturally fractured, canhave been previously fractured one or more times (e.g., fractured, orfractured and refractured one or more times), or any combinationthereof. The fracturing of the second wellbore can comprise fracturingor refracturing of a region of the unconventional subterranean formationin fluid communication with the second wellbore.

Also provided are analogous pressure protection methods which employfoamed pressure protection compositions. For example, in someembodiments, a foam can be injected into the existing wellbore toprovide pressure protection to the existing wellbore prior to fracturinga new wellbore proximate to the existing wellbore. The foam can compriseany suitable foam known for use in oil and gas operations. The foam canbe formed using any suitable expansion gas as discussed in detail below,such as, for example, air, helium, carbon dioxide, nitrogen, natural gasor a hydrocarbon component thereof, or any combination thereof.

Accordingly, also provided are methods for pressure protection of anexisting wellbore that has previously been fractured in proximity to anew wellbore to be fractured that comprise (a) injecting a foamedpressure protection composition into the unconventional subterraneanformation via an existing wellbore in fluid communication with a rockmatrix of the unconventional subterranean formation prior to and/orduring injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. As discussed above with respect to aqueouspressure protection compositions, the foamed pressure protectionsolution can be injected at a pressure and flowrate effective toincrease the existing wellbore pressure without substantiallyrefracturing the existing wellbore.

Also provided are analogous pressure protection methods which employnon-aqueous pressure protection compositions. For example, in someembodiments, a gas can be injected into the existing wellbore to providepressure protection to the existing wellbore prior to fracturing a newwellbore proximate to the existing wellbore. The gas can comprise anysuitable gas, such as, for example, air, helium, carbon dioxide,nitrogen, natural gas or a hydrocarbon component thereof, or anycombination thereof.

Example methods can comprise (a) injecting a gas into the unconventionalsubterranean formation via an existing wellbore in fluid communicationwith a rock matrix of the unconventional subterranean formation prior toand/or during injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. As discussed above with respect to aqueouspressure protection compositions, the gas can be injected at a pressureand flowrate effective to increase the existing wellbore pressurewithout substantially refracturing the existing wellbore.

Other methods can employ suitable hydrocarbon-based pressure protectioncomposition. For example, pressure protection compositions comprising ahydrocarbon solvent (e.g., liquid petroleum gas (LPG)) can be injectedinto the existing wellbore to provide pressure protection to theexisting wellbore prior to and/or during fracturing a new wellboreproximate to the existing wellbore. These hydrocarbon-based pressureprotection compositions can comprise any of the components describedabove with respect to aqueous pressure protection compositions. Forexample, hydrocarbon-based pressure protection compositions can comprisea surfactant package, an acid, an alkali agent, a co-solvent, aviscosity-modifying polymer, or any combination thereof.

Example methods can comprise (a) injecting a pressure protectioncomposition comprising a hydrocarbon solvent into the unconventionalsubterranean formation via an existing wellbore in fluid communicationwith a rock matrix of the unconventional subterranean formation prior toand/or during injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. As discussed above with respect to aqueouspressure protection compositions, the pressure protection compositioncan be injected at a pressure and flowrate effective to increase theexisting wellbore pressure without substantially refracturing theexisting wellbore.

DESCRIPTION OF DRAWINGS

FIG. 1A shows the results of simulations showing the beneficial effectof pre-loading an existing (parent) well with an aqueous compositionprior to fracturing of the new (child) well. As shown in the simulation,water pre-load improves new (child) well fracture propagation towardsvirgin rock as opposed to towards the previously fractured rock matrixin proximity to the existing well.

FIG. 1B is a plot illustrating the projected improvement in oil recoveryas a result of pre-loading with an aqueous pressure protectioncomposition. Pre-loading results in a 6% EUR uplift in child wellproduction as a consequence of pre-loading in this simulation example.

FIG. 2 is a plot illustrating the results of pilot 1. The plotillustrates the normalized rate of hydrocarbon production post fracversus post frac time for wells treated with surfactant pre-loading,water pre-loading as well as wells with no pre-loading.

FIG. 3 is a plot illustrating the results of pilot 2. The plotillustrates the normalized rate of hydrocarbon production post fracversus post frac time for wells treated with surfactant pre-loading andwater pre-loading.

DETAILED DESCRIPTION

As used in this specification and the following claims, the terms“comprise” (as well as forms, derivatives, or variations thereof, suchas “comprising” and “comprises”) and “include” (as well as forms,derivatives, or variations thereof, such as “including” and “includes”)are inclusive (i.e., open-ended) and do not exclude additional elementsor steps. For example, the terms “comprise” and/or “comprising,” whenused in this specification, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof. Accordingly, these terms are intended to not only cover therecited element(s) or step(s), but may also include other elements orsteps not expressly recited. Furthermore, as used herein, the use of theterms “a” or “an” when used in conjunction with an element may mean“one,” but it is also consistent with the meaning of “one or more,” “atleast one,” and “one or more than one.” Therefore, an element precededby “a” or “an” does not, without more constraints, preclude theexistence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of ±10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) can includes 10% and also includes 20%,and includes percentages in between 10% and 20%, unless explicitlystated otherwise herein.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifa composition is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the composition describedby this phrase could include only a component of type A. In someembodiments, the composition described by this phrase could include onlya component of type B. In some embodiments, the composition described bythis phrase could include only a component of type C. In someembodiments, the composition described by this phrase could include acomponent of type A and a component of type B. In some embodiments, thecomposition described by this phrase could include a component of type Aand a component of type C. In some embodiments, the compositiondescribed by this phrase could include a component of type B and acomponent of type C. In some embodiments, the composition described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the compositiondescribed by this phrase could include two or more components of type A(e.g., A1 and A2). In some embodiments, the composition described bythis phrase could include two or more components of type B (e.g., B1 andB2). In some embodiments, the composition described by this phrase couldinclude two or more components of type C (e.g., C1 and C2). In someembodiments, the composition described by this phrase could include twoor more of a first component (e.g., two or more components of type A (A1and A2)), optionally one or more of a second component (e.g., optionallyone or more components of type B), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the composition described by this phrase could include twoor more of a first component (e.g., two or more components of type B (B1and B2)), optionally one or more of a second component (e.g., optionallyone or more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the composition described by this phrase could include twoor more of a first component (e.g., two or more components of type C (C1and C2)), optionally one or more of a second component (e.g., optionallyone or more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B).

“Hydrocarbon-bearing formation” or simply “formation” refers to the rockmatrix in which a wellbore may be drilled. For example, a formationrefers to a body of rock that is sufficiently distinctive and continuoussuch that it can be mapped. It should be appreciated that while the term“formation” generally refers to geologic formations of interest, thatthe term “formation,” as used herein, may, in some instances, includeany geologic points or volumes of interest (such as a survey area).

“Unconventional formation” is a subterranean hydrocarbon-bearingformation that generally requires intervention in order to recoverhydrocarbons from the reservoir at economic flow rates or volumes. Forexample, an unconventional formation includes reservoirs having anunconventional microstructure in which fractures are used to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes(e.g., an unconventional reservoir generally needs to be fractured underpressure or have naturally occurring fractures in order to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes).

In some embodiments, the unconventional formation can include areservoir having a permeability of less than 25 millidarcy (mD) (e.g.,20 mD or less, 15 mD or less, 10 mD or less, 5 mD or less, 1 mD or less,0.5 mD or less, 0.1 mD or less, 0.05 mD or less, 0.01 mD or less, 0.005mD or less, 0.001 mD or less, 0.0005 mD or less, 0.0001 mD or less,0.00005 mD or less, 0.00001 mD or less, 0.000005 mD or less, 0.000001 mDor less, or less). In some embodiments, the unconventional formation caninclude a reservoir having a permeability of at least 0.000001 mD (e.g.,at least 0.000005 mD, at least 0.00001 mD, 0.00005 mD, at least 0.0001mD, 0.0005 mD, 0.001 mD, at least 0.005 mD, at least 0.01 mD, at least0.05 mD, at least 0.1 mD, at least 0.5 mD, at least 1 mD, at least 5 mD,at least 10 mD, at least 15 mD, or at least 20 mD).

The unconventional formation can include a reservoir having apermeability ranging from any of the minimum values described above toany of the maximum values described above. For example, in someembodiments, the unconventional formation can include a reservoir havinga permeability of from 0.000001 mD to 25 mD (e.g., from 0.001 mD to 25mD, from 0.001 mD to 10 mD, from 0.01 mD to 10 mD, from 0.1 mD to 10 mD,from 0.001 mD to 5 mD, from 0.01 mD to 5 mD, or from 0.1 mD to 5 mD).

The formation may include faults, fractures (e.g., naturally occurringfractures, fractures created through hydraulic fracturing, etc.),geobodies, overburdens, underburdens, horizons, salts, salt welds, etc.The formation may be onshore, offshore (e.g., shallow water, deep water,etc.), etc. Furthermore, the formation may include hydrocarbons, such asliquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons,a combination of hydrocarbons (e.g., a combination of liquidhydrocarbons and gas hydrocarbons (e.g. including gas condensate)), etc.

The formation, the hydrocarbons, or both may also includenon-hydrocarbon items, such as pore space, connate water, brine, fluidsfrom enhanced oil recovery, etc. The formation may also be divided upinto one or more hydrocarbon zones, and hydrocarbons can be producedfrom each desired hydrocarbon zone.

The term formation may be used synonymously with the term reservoir or“subsurface reservoir” or “subsurface region of interest” or “subsurfaceformation” or “subsurface volume of interest”. In some embodiments, thereservoir may be, but is not limited to, a shale reservoir, etc. Indeed,the terms “formation,” “reservoir,” “hydrocarbon,” and the like are notlimited to any description or configuration described herein.

“Wellbore” refers to a continuous hole for use in hydrocarbon recovery,including any openhole or uncased portion of the wellbore. For example,a wellbore may be a cylindrical hole drilled into the formation suchthat the wellbore is surrounded by the formation, including rocks,sands, sediments, etc. A wellbore may be used for injection. A wellboremay be used for production. A wellbore may be used for hydraulicfracturing of the formation. A wellbore even may be used for multiplepurposes, such as injection and production. The wellbore may havevertical, inclined, horizontal, or a combination of trajectories. Forexample, the wellbore may be a vertical wellbore, a horizontal wellbore,a multilateral wellbore, an inclined wellbore, a slanted wellbore, etc.The deviation of the wellbore may change, for example, the deviation ischanging when the wellbore is curving. The wellbore may include aplurality of components, such as, but not limited to, a casing, a liner,a tubing string, a heating element, a sensor, a packer, a screen, agravel pack, etc. The wellbore may also include equipment to controlfluid flow into the wellbore, control fluid flow out of the wellbore, orany combination thereof. For example, each wellbore may include awellhead, a BOP, chokes, valves, or other control devices. These controldevices may be located on the surface, under the surface (e.g., downholein the wellbore), or any combination thereof. The wellbore may alsoinclude at least one artificial lift device, such as, but not limitedto, an electrical submersible pump (ESP) or gas lift. The wellbore maybe drilled into the formation using practically any drilling techniqueand equipment known in the art, such as geosteering, directionaldrilling, etc. The term wellbore may be used synonymously with the termsborehole or well.

“Fracturing” is one way that hydrocarbons may be recovered (sometimesreferred to as produced) from the formation. For example, hydraulicfracturing may entail preparing a fracturing fluid and injecting thatfracturing fluid into the wellbore at a sufficient rate and pressure toopen existing fractures and/or create fractures in the formation. Thefractures permit hydrocarbons to flow more freely into the wellbore. Inthe hydraulic fracturing process, the fracturing fluid may be preparedon-site to include at least proppants. The proppants, such as sand orother particles, are meant to hold the fractures open so thathydrocarbons can more easily flow to the wellbore. The fracturing fluidand the proppants may be blended together using at least one blender.The fracturing fluid may also include other components in addition tothe proppants.

The wellbore and the formation proximate to the wellbore are in fluidcommunication (e.g., via perforations), and the fracturing fluid withthe proppants is injected into the wellbore through a wellhead of thewellbore using at least one pump (oftentimes called a fracturing pump).The fracturing fluid with the proppants is injected at a sufficient rateand pressure to open existing fractures and/or create fractures in thesubsurface volume of interest. As fractures become sufficiently wide toallow proppants to flow into those fractures, proppants in thefracturing fluid are deposited in those fractures during injection ofthe fracturing fluid. After the hydraulic fracturing process iscompleted, the fracturing fluid is removed by flowing or pumping it backout of the wellbore so that the fracturing fluid does not block the flowof hydrocarbons to the wellbore. The hydrocarbons will typically enterthe same wellbore from the formation and go up to the surface forfurther processing.

The equipment to be used in preparing and injecting the fracturing fluidmay be dependent on the components of the fracturing fluid, theproppants, the wellbore, the formation, etc. However, for simplicity,the term “fracturing apparatus” is meant to represent any tank(s),mixer(s), blender(s), pump(s), manifold(s), line(s), valve(s), fluid(s),fracturing fluid component(s), proppants, and other equipment andnon-equipment items related to preparing the fracturing fluid andinjecting the fracturing fluid.

Other hydrocarbon recovery processes may also be utilized to recover thehydrocarbons. Furthermore, those of ordinary skill in the art willappreciate that one hydrocarbon recovery process may also be used incombination with at least one other recovery process or subsequent to atleast one other recovery process.

“Friction reducer,” as used herein, refers to a chemical additive thatalters fluid rheological properties to reduce friction created withinthe fluid as it flows through small-diameter tubulars or similarrestrictions (e.g., valves, pumps). Generally polymers, or similarfriction reducing agents, add viscosity to the fluid, which reduces theturbulence induced as the fluid flows. Reductions in fluid friction ofgreater than 50% (e.g., from 50% to 250% or from 50% to 100%) arepossible depending on the friction reducer utilized, which allows theinjection fluid to be injected into a wellbore at a much higherinjection rate (e.g., between 60 to 100 barrels per minute) and alsolower pumping pressure during proppant injection.

“Injection fluid,” as used herein, refers to any fluid which is injectedinto a reservoir via a well. “Fracturing fluid,” as used herein, refersto an injection fluid that is injected into the well under pressure inorder to cause fracturing within a portion of the reservoir.

The term “interfacial tension” or “IFT” as used herein refers to thesurface tension between test oil and water of different salinitiescontaining a surfactant formulation at different concentrations.Typically, interfacial tensions are measured using a spinning droptensiometer or calculated from phase behavior experiments.

The term “proximate” is defined as “near”. If item A is proximate toitem B, then item A is near item B. For example, in some embodiments,item A may be in contact with item B. For example, in some embodiments,there may be at least one barrier between item A and item

B such that item A and item B are near each other, but not in contactwith each other. The barrier may be a fluid barrier, a non-fluid barrier(e.g., a structural barrier), or any combination thereof. Both scenariosare contemplated within the meaning of the term “proximate.”

Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs. Unless otherwise specified,all percentages are in weight percent and the pressure is inatmospheres. All citations referred to herein are expressly incorporatedby reference.

Methods

Provided are methods for the pressure protection of wells (e.g., bypre-loading the wells) using the aqueous pressure protectioncompositions described herein.

Methods for the pressure protection of an existing wellbore that haspreviously been fractured in proximity to a new wellbore to be fracturedcan comprise (a) injecting an aqueous pressure protection compositioninto the unconventional subterranean formation via an existing wellborein fluid communication with a rock matrix of the unconventionalsubterranean formation prior to and/or during injection of a fracturingfluid into the unconventional subterranean formation via a new wellborein fluid communication with the rock matrix of the unconventionalsubterranean formation; and (b) producing a hydrocarbon from theexisting wellbore during and/or after the injection of the fracturingfluid into the unconventional subterranean formation via the newwellbore.

The rock matrix of the unconventional subterranean formation inproximity to the existing wellbore can be fractured. For example, insome embodiments, the rock matrix of the unconventional subterraneanformation in proximity to the existing wellbore can have been previouslyfractured (e.g., by injection of a fracturing fluid). In otherembodiments, the rock matrix of the unconventional subterraneanformation in proximity to the existing wellbore has not been previouslyfractured, but the rock matrix of the unconventional subterraneanformation is naturally fractured. In other embodiments, the rock matrixof the unconventional subterranean formation is naturally fractured andthe rock matrix of the unconventional subterranean formation inproximity to the existing wellbore has been previously fractured (e.g.,by injection of a fracturing fluid).

The aqueous pressure protection solution can be injected at a pressureand flowrate effective to increase the existing wellbore pressure,stress, or any combination thereof without substantially refracturingthe existing wellbore. The volume of aqueous pressure protectionsolution injected can be selected to increase the existing wellborepressure and stress without substantially refracturing the existingwellbore.

As is known in the art, the pressure profile can be monitored duringinjection of the aqueous pressure protection solution into the existingwellbore. During injection without substantially refracturing theexisting wellbore, the pressure will generally increase as the aqueouspressure protection solution is injected into the existing wellbore.When the injection pressure begins to plateau, this indicatessubstantial refracturing of the existing wellbore is occurring. Thephrase “substantially refracturing the existing wellbore,” as usedherein, refers to circumstances where no fracturing is observed (in theform of plateauing) when monitoring injection pressure during injectionof the aqueous pressure protection composition.

In some embodiments, there is no need to drill the existing wellbore andthe new wellbore. In some embodiments, the existing wellbore has beendrilled, the existing wellbore has been completed, and hydrocarbonproduction has occurred from the existing wellbore. In some embodiments,the new wellbore has been drilled. Furthermore, in some embodiments, thenew wellbore may not be completed and the region proximate to the newwellbore has not been previously fractured by hydraulic fracturing. Inother embodiments, methods can optionally include one or more ofdrilling the existing wellbore, completing the existing wellbore,producing hydrocarbons from the existing wellbore (prior to injection ofthe aqueous pressure protection composition), or drilling the newwellbore in proximity to the existing wellbore.

Further, while embodiments are generally discussed herein referencing asingle existing wellbore and a single new wellbore, one of ordinaryskill in the art will understand that the methods described herein applyto circumstances which include a plurality of existing wellboresproximate to a single new wellbore, a plurality of new wellboresproximate to a single existing wellbore, or a plurality of existingwellbores proximate to a plurality of new wellbores.

In some embodiments, the existing wellbore was under production prior toinjection of the aqueous pressure protection composition. For example,in some embodiments, the existing wellbore was under production for atleast three months (e.g., at least six months, at least one year, atleast two years, at least three years, at least four years, at leastfive years, at least ten years, at least twenty years, or more) prior toinjection of the aqueous pressure protection composition. In certainembodiments, the existing wellbore was under production for from threemonths to twenty years (e.g., from one year to ten years, or from oneyear to five years) prior to injection of the aqueous pressureprotection composition.

In some embodiments, at least 10,000 barrels of hydrocarbon (e.g., atleast 20,000 barrels of hydrocarbon, at least 30,000 barrels ofhydrocarbon, at least 40,000 barrels of hydrocarbon, at least 50,000barrels of hydrocarbon, at least 100,000 barrels of hydrocarbon, atleast 200,000 barrels of hydrocarbon, at least 300,000 barrels ofhydrocarbon, at least 400,000 barrels of hydrocarbon, at least 500,000barrels of hydrocarbon, or more) were produced from the existingwellbore prior to injection of the aqueous pressure protectioncomposition. In some embodiments, from 10,000 barrels of hydrocarbon to500,000 barrels of hydrocarbon were produced from the existing wellboreprior to injection of the aqueous pressure protection composition.

In some examples, the existing wellbore can have a pressure that is from5% to 70% of the original reservoir pressure. The original reservoirpressure and the existing wellbore pressure can be measured usingstandard methods known in the art. The original reservoir pressure canbe measured during and/or after of drilling of the existing wellbore(prior to any hydrocarbon production) using, for example, downholegauges, fiber optics equipment, or other logging equipment. Should noequipment be available, the surface pressure can be used along with thedensity/height of the fluid column to estimate the original reservoirpressure using the equation: P(surface pressure)+pgh=P(bottomholepressure). Likewise, the existing wellbore pressure can be measuredimmediately prior to injection of the aqueous pressure protectioncomposition using, for example, downhole gauges, fiber optics equipment,or other logging equipment. Should no equipment be available, thesurface pressure can be used along with the density/height of the fluidcolumn to estimate the original reservoir pressure using the equation:

P(surface pressure)+pgh=P(bottomhole pressure).

Step (a) can comprise injecting the aqueous pressure protectioncomposition at a pressure and flowrate effective to increase theexisting wellbore pressure by at least 5% (e.g., at least 10% at least20%, at least 30%, at least 40%, at least 50%, at least 60%, at least70%, at least 80%, at least 90%, at least 100%, at least 110%, at least120%, at least 130%, at least 140%, at least 150%, at least 160%, atleast 170%, at least 180%, at least 190%, at least 200%, at least 250%,at least 300%, at least 400%, or at least 500%). In some embodiments,step (a) can comprise injecting the aqueous pressure protectioncomposition at a pressure and flowrate effective to increase theexisting wellbore pressure by from 5% to 500% (e.g., from 50% to 500%,or from 100% to 500%).

Step (a) can comprise injecting a volume of the aqueous pressureprotection composition effective to increase the existing wellborepressure by at least 5% (e.g., at least 10% at least 20%, at least 30%,at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, atleast 90%, at least 100%, at least 110%, at least 120%, at least 130%,at least 140%, at least 150%, at least 160%, at least 170%, at least180%, at least 190%, at least 200%, at least 250%, at least 300%, atleast 400%, or at least 500%). In some embodiments, step (a) cancomprise injecting a volume of the aqueous pressure protectioncomposition effective to increase the existing wellbore pressure by from5% to 500% (e.g., from 50% to 500%, or from 100% to 500%).

In some examples, step (a) can comprise injecting the aqueous pressureprotection composition at a pressure and flowrate effective to increasethe existing wellbore pressure to from greater than the originalreservoir pressure to 150% of the original reservoir pressure.

In some examples, step (a) can comprise injecting a volume of theaqueous pressure protection composition effective to increase theexisting wellbore pressure to from greater than the original reservoirpressure to 150% of the original reservoir pressure.

The original reservoir fracture pressure and existing reservoir fracturepressure can be measured using standard methods. For example, theoriginal reservoir fracture pressure can be measured using a mini-fracand DFIT method between drilling and fracturing to measure the originalreservoir fracture pressure (see, for example, the methods described athttp://www.fekete.com/SAN/TheoryAndEquations/WellTestTheoryEquations/Minifrac.htm).Likewise, the existing reservoir fracture pressure can be measured usinga mini-frac and DFIT method between drilling and fracturing to measurethe existing reservoir fracture pressure. Empirical equations, such asthose described in Zhang et al. (“Fracture Gradient Prediction: AnOverview and an Improved Method,” Pet. Sci., 2017, 14: 720-730, which ishereby incorporated by reference), can be used to account for changes instresses and pore pressure due to the depletion of fluids. The existingreservoir fracture pressure can also be measured in a laboratory usingreservoir rock, fluids, and standard testing methods.

In some examples, step (a) can comprise injecting the aqueous pressureprotection composition at a pressure and flowrate effective to increasethe existing wellbore pressure to within 15% (e.g., ±15%) of existingreservoir fracture pressure (so as to not substantially refracture theexisting wellbore). Step (b) can comprise injecting the aqueous pressureprotection composition at least two weeks before fracturing, optionallyinjecting the aqueous pressure protection composition at least one weekbefore fracturing, at least 5 days before fracturing, at least 4 daysbefore fracturing, at least 3 days before fracturing, at least 2 daysbefore fracturing, or at least 1 day before fracturing.

In some examples, step (a) can comprise injecting a volume of theaqueous pressure protection composition effective to increase theexisting wellbore pressure to within 15% (e.g., ±15%) of existingreservoir fracture pressure (so as to not substantially refracture therock matrix in proximity to the existing wellbore).

In some embodiments, the original reservoir pressure can be at least4000 psia (e.g., at least 5000 psia, at least 6000 psia, at least 7000psia, at least 8000 psia, or at least 9000 psia). In some embodiments,the original reservoir pressure can be 10000 psia or less (e.g., 9000psia or less, 8000 psia or less, 7000 psia or less, 6000 psia or less,or 5000 psia or less). In some cases, the original reservoir pressurecan range from any of the minimum values described above to any of themaximum values described above. For example, in some embodiments, theoriginal reservoir pressure can be from 4000 psia to 10000 psia (e.g.,from 5000 psia to 10000 psia).

In some embodiments, the original reservoir fracture pressure can be atleast 5000 psia (e.g., at least 6000 psia, at least 7000 psia, at least8000 psia, at least 9000 psia, at least 10000 psia, or at least 11000psia). In some embodiments, the original reservoir fracture pressure canbe 12000 psia or less (e.g., 11000 psia or less, 10000 psia or less,9000 psia or less, 8000 psia or less, 7000 psia or less, 6000 psia orless, or 5000 psia or less).

In some cases, the original reservoir fracture pressure can range fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the originalreservoir fracture pressure can be from 5000 psia to 12000 psia (e.g.,from 6000 psia to 10000 psia).

In some embodiments, the existing wellbore pressure can be at least 500psia (e.g., at least 1000 psia, at least 2000 psia, at least 3000 psia,at least 4000 psia, or at least 5000 psia). In some embodiments, theexisting wellbore pressure can be 6000 psia or less (e.g., 5000 psia orless, 4000 psia or less, 3000 psia or less, 2000 psia or less, or 1000psia or less).

In some cases, the existing wellbore pressure can range from any of theminimum values described above to any of the maximum values describedabove. For example, in some embodiments, the existing wellbore pressurecan be from 500 psia to 6000 psia (e.g., from 1000 psia to 4000 psia).

In some embodiments during a pressure protection operation describedherein, the aqueous pressure protection composition can be injected at apressure and flowrate effective to increase the existing wellborepressure to at least 4000 psia (e.g., at least 5000 psia, at least 6000psia, at least 7000, at least 8000 psia, or at least 9000 psia). In someembodiments during a pressure protection operation described herein, theaqueous pressure protection composition can be injected at a pressureand flowrate effective to increase the existing wellbore pressure to10000 psia or less (e.g., 9000 psia or less, 8000 psia or less, 7000psia or less, 6000 psia or less, or 5000 psia or less).

In some cases during a pressure protection operation described herein,the aqueous pressure protection composition can be injected at apressure and flowrate effective to increase the existing wellborepressure to a pressure ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments during a pressure protection operation described herein, theaqueous pressure protection composition can be injected at a pressureand flowrate effective to increase the existing wellbore pressure tofrom 4000 psia to 10000 psia.

In some embodiments during a pressure protection operation describedherein, the volume of the aqueous pressure protection compositioninjected can be effective to increase the existing wellbore pressure toat least 4000 psia (e.g., at least 5000 psia, at least 6000 psia, atleast 7000, at least 8000 psia, or at least 9000 psia). In someembodiments during a pressure protection operation described herein, thevolume of the aqueous pressure protection composition injected can beeffective to increase the existing wellbore pressure to 10000 psia orless (e.g., 9000 psia or less, 8000 psia or less, 7000 psia or less,6000 psia or less, or 5000 psia or less).

In some cases during a pressure protection operation described herein,the volume of the aqueous pressure protection composition injected canbe effective to increase the existing wellbore pressure to a pressureranging from any of the minimum values described above to any of themaximum values described above. For example, in some embodiments duringa pressure protection operation described herein, the volume of theaqueous pressure protection composition injected can be effective toincrease the existing wellbore pressure to from 4000 psia to 10000 psia.

By way of example, in some embodiments, the original reservoir pressurecan be approximately 6000-7000 psia, and an original reservoir fracturepressure of from approximately 8000-9000 psia. After 1 year ofproduction, the existing wellbore can have a wellbore pressuresubstantially below original reservoir pressure. For example, after 1year of production, the existing wellbore pressure can drop toapproximately 3000-4000 psia. After more than a year, the existingwellbore pressure can drop even further (e.g., to approximately2000-3000 psia). During a pressure protection operation describedherein, the aqueous pressure protection composition can be injected at apressure and flowrate effective to increase the existing wellborepressure to approximately 4000-9000 psia.

In some embodiment, a single aqueous pressure protection composition canbe injected into the existing wellbore. In other embodiments, injectionof the aqueous pressure protection composition into the existingwellbore can comprise sequential injection of a series (e.g., two,three, four, or five) of aqueous pressure protection compositions ofvarying composition into the existing wellbore. The series of injectionscan, in combination, increase the existing wellbore pressure to itsdesired level for pressure protection of the existing wellbore.

By way of example, in some embodiments, injection can comprise injectionof a first aqueous pressure protection composition into the existingwellbore followed by injection of a second aqueous pressure protectioncomposition into the existing wellbore. In some of these embodiments,the first aqueous protection composition can be allowed to soak incontact with the formation for a period of time (e.g., for example, 1hour, 2 hours, 6 hours, 12 hours, 24 hours, 48 hours, 72 hours, 1 week,2 week, 3 weeks, 1 month or more) prior to injection of the secondpressure protection composition. In some of these embodiments, the firstaqueous pressure protection composition can comprise acid (e.g., HCl orHF). In some of these embodiments, the second aqueous pressureprotection composition can comprise an alkali, a surfactant, or anycombination thereof. In some of these embodiments, the total volume ofthe first aqueous pressure protection composition and the second aqueouspressure protection composition can be effective to increase theexisting wellbore pressure to from greater than the original reservoirpressure to 150% of the original reservoir pressure. In some of theseembodiments, methods can further comprise injection of a third pressureprotection composition (e.g., a hydrocarbon solvent such as LPG, or agas such as CO₂ or natural gas, as discussed in more detail below) intothe existing wellbore.

In another embodiment, injection can comprise injection of a firstaqueous pressure protection composition into the existing wellborefollowed by injection of a second pressure protection composition intothe existing wellbore. In some embodiments, the first aqueous pressureprotection composition can comprise an alkali, a surfactant, or anycombination thereof. In some embodiments, the second pressure protectioncomposition can comprise a hydrocarbon solvent such as LPG, or a gassuch as CO₂ or natural gas, as discussed in more detail below.

In another embodiment, injection can comprise alternating injections ofan aqueous pressure protection composition (e.g., comprising an alkali,a surfactant, or any combination thereof) and a gas (e.g., CO₂ ornatural gas). In some embodiments, injection can comprise injection of afirst aqueous pressure protection composition (e.g., comprising an acidsuch as HCl or HF) followed by alternating injections of an aqueouspressure protection composition (e.g., an alkali, a surfactant, or anycombination thereof) and a gas (e.g., CO₂ or natural gas).

In another embodiment, injection can comprise alternating injections ofa pressure protection composition comprising a hydrocarbon solvent(e.g., a pressure protection composition comprising LPG) and a gas(e.g., CO₂ or natural gas). In some embodiments, injection can compriseinjection of a first aqueous pressure protection composition (e.g.,comprising an acid such as HCl or HF) followed by alternating injectionsof a pressure protection composition comprising a hydrocarbon solvent(e.g., a pressure protection composition comprising LPG) and a gas(e.g., CO₂ or natural gas).

The aqueous pressure protection composition can be injected into theexisting wellbore prior to and/or during injection of a fracturing fluidinto the unconventional subterranean formation via the new wellbore. Theaqueous pressure protection composition can be maintained within theexisting wellbore during the course of a fracturing operation performedin the new wellbore. If desired, injection of the aqueous pressureprotection composition can be continued after completion of a fracturingoperation performed using the new wellbore.

In some embodiments, methods can further comprise performing afracturing operation in the new wellbore. For example, methods canfurther comprise injecting a fracturing fluid into the unconventionalsubterranean formation via the new wellbore at a sufficient pressure tocreate or extend at least one fracture in a rock matrix of theunconventional subterranean formation in a region proximate to the newwellbore.

In some embodiments, injection of the aqueous pressure protectioncomposition in the existing wellbore impacts a direction, a geometry, orany combination thereof of the at least one fracture created or extendedin the rock matrix during injection of the fracturing fluid into theunconventional subterranean formation via the new wellbore. For example,the aqueous protection composition in the existing wellbore can directfracture formation away from the fractured region proximate to theexisting wellbore, and towards virgin rock proximate to the newwellbore.

In some embodiments, the injection of the aqueous pressure protectioncomposition in the existing wellbore can reduce entry of fluid, debris,or any combination thereof into the existing wellbore during injectionof the fracturing fluid into the unconventional subterranean formationvia the new wellbore.

In some embodiments, the method further comprises producing ahydrocarbon from the existing wellbore during and/or after the injectionof the fracturing fluid into the unconventional subterranean formationvia the new wellbore. In some embodiments, injection of the aqueouspressure protection composition into the existing wellbore can decreasethe decline of a decline curve fit to production history of the existingwellbore.

In some embodiments, the method can further result in increasedhydrocarbon recovery from the existing wellbore, the new wellbore, orany combination thereof. For example, injection of the aqueous pressureprotection composition into the existing wellbore can result inincreased hydrocarbon recovery from the existing wellbore as compared toan expected level of hydrocarbon recovery projected from a decline curvefit to production history of the existing wellbore. The decline curvecan be fit to production history of the existing wellbore using, forexample, Arp's Equation. Methods for determining decline curves forproduction wells are well known in the art. See, for example,“Estimating Ultimate Recovery of Developed Wells in Low-PermeabilityReservoirs,” Monograph 4, Society of Petroleum Engineers (ISBN9781938330018) and “Guidelines for the Practical Evaluation ofUndeveloped Reserves in Resource Plays,” Monograph 3, Society ofPetroleum Engineers (2010), each of which is hereby incorporated byreference in its entirety.

In some embodiments, injection of the aqueous pressure protectioncomposition in the existing wellbore can increase the relativepermeability in a region proximate to the existing wellbore.

In some embodiments, injection of the aqueous pressure protectioncomposition in the existing wellbore releases hydrocarbons from pores inthe rock matrix in the region proximate to the existing wellbore.

Optionally, in some embodiments, the method can further comprisemodeling the existing wellbore and the region proximate to the existingwellbore to determine a volume of the aqueous pressure protectioncomposition to be injected into the unconventional subterraneanformation via the existing wellbore.

Also provided are methods for pressure protection of a first wellbore inproximity to a second wellbore. These methods can comprise injecting anaqueous pressure protection composition into the first wellbore in fluidcommunication with an unconventional subterranean formation prior toand/or during fracturing of the second wellbore in fluid communicationwith the unconventional subterranean formation. The first wellbore canhave an existing reservoir pressure that is less than original reservoirpressure. The aqueous pressure protection solution can be injected at apressure and flowrate effective to increase the first wellbore pressurewithout fracturing the first wellbore. The aqueous pressure protectionsolution can include a surfactant package including a first surfactant.A region of the unconventional subterranean formation in fluidcommunication with the first wellbore can be naturally fractured, canhave been previously fractured one or more times (e.g., fractured, orfractured and refractured one or more times), or any combinationthereof. The fracturing of the second wellbore can comprise fracturingor refracturing of a region of the unconventional subterranean formationin fluid communication with the second wellbore.

The methods described herein may involve one or more of the following:

(1) Determining which wells require preloading based on geomechanicalanalysis (e.g., performing preloading on all existing wells that lie onthe fracture plane adjacent to the planned new child well).

(2) Preparing existing (parent or teenage) wells for preloading. Thiscan include pulling/replacing any low pressure downhole valves that maybe damaged during the new (child) well fracturing operation due tohigher expected pressures. For example, a slickline intervention can beperformed to retrieve low pressure side pocket mandrel valves used forgas lifted wells and the tubing, rods, and pump can be pulled on rodpump artificial lift wells. Existing wells may also be shut-in for aperiod of time prior to the preload operation.

(3) Installing downhole surveillance equipment to monitor pressure inexisting (parent or teenage) wells. Use of pressure information may aidin identifying the ideal time period to perform fracturing operations inthe child well, as well as, determining the amount of injection solutionto use during a preload operation in the existing wells.

(4) Shutting-in the existing wells closer to the new child well for atleast for 24 hours.

(5) Preloading existing wells closer to the new child well with largeramount of injection solution (e.g., injecting 20,000 bbls of injectionsolution in an existing parent well immediately adjacent to the newchild well and injecting only 10,000 bbls of injection solution in anexisting teenage well that is further from the new child well). Existingwells farther away from the new child well may alternatively be shut-inor continue producing instead of undergoing a preload operation.

(6) Pre-loading solution can be injected all at once or at differentsteps. For example, acid can be injected at the beginning to clean outthe wellbore area and alter the rock wettability mixed with or followedby the surfactant and/or alkaline solutions.

(7) Preloading existing wells closer to the new child well with oneinjection solution and preloading existing wells farther from the newchild well with a similar solution or a different injection solution.

(8) Injecting a sulfide scavenger with the injection solution to reducethe risk of sulfide stress cracking of wells if hydrogen sulfide hasbeen detected or is a factor in the reservoir being produced.

(9) Swabbing in existing wells to unload preload fluids from theproduction tubing and return existing wells to production subsequent toperforming the fracturing operation on the child well.

(10) Shut-in the pre-loaded existing wells during the fracturing of thenew child well.

(11) Continuing injection of the aqueous pressure protection compositionfor a period of time after the new wellbore has been fractured.

Aqueous Pressure Protection Compositions

The aqueous pressure protection compositions described herein caninclude one or more components which can improve hydrocarbon recoveryfrom the existing wellbore (e.g., following pressureprotection/pre-loading with the aqueous pressure protectioncomposition). Examples of such components include a surfactant package,an acid, an alkali agent, a co-solvent, a viscosity-modifying polymer,or any combination thereof.

Additional additives can also be incorporated in the aqueous pressureprotection compositions, such as a chelating agent (e.g., EDTA or a saltthereof, for example, for use as an iron control agent), a clay swellinginhibitor (e.g., KC1), a biocide, a scale inhibitor, an anti-foam agent(e.g., chemical defoamer), a corrosion inhibitor, a sulfide scavenger,or any combination thereof.

The aqueous pressure protection compositions can comprise any type ofwater, treated or untreated, and can vary in salt content. For example,the aqueous pressure protection composition can comprise sea water,brackish water, flowback or produced water, wastewater (e.g., reclaimedor recycled), brine (e.g., reservoir or synthetic brine), fresh water(e.g., fresh water comprises <1,000 ppm TDS water), or any combinationthereof. In some embodiments, the aqueous-based injection fluid cancomprise slickwater.

In some embodiments, the aqueous pressure protection compositions can besubstantially free of proppant particles.

In some embodiments, the aqueous pressure protection composition can bein the form of an aqueous solution. In these embodiments, the aqueouspressure protection compositions can comprise from 30% to 99.85% byweight of the total composition of water, for example from 70% to 98%water.

Acids

In some embodiments, the aqueous pressure protection composition cancomprise an acid. The acid can comprise any suitable acid known in theart. In some embodiments, the acid can comprise a strong acid, such asHCl, HF, or any combination thereof. In other embodiments, the acid cancomprise a weak acid, such as an organic acid (e.g., acetic acid, citricacid, tartric acid, or any combination thereof).

In some embodiments, the aqueous pressure protection composition canhave a pH of at least 2 (e.g., at least 2.5, at least 3, at least 3.5,at least 4, at least 4.5, at least 5, or at least 5.5). In someembodiments, the aqueous pressure protection composition can have a pHof 6 or less (e.g., 5.5 or less, 5 or less, 4.5 or less, 4 or less, 3.5or less, 3 or less, or 2.5 or less).

The aqueous pressure protection composition can have a pH ranging fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the aqueous pressureprotection composition can have a pH of from 2 to 6 (e.g., from 2 to5.5, from 2 to 4, or from 2 to 3).

Alkali Agents

In some embodiments, the aqueous pressure protection composition cancomprise an alkali agent.

The term “alkali agent” is used herein according to its conventionalmeaning and includes basic, ionic salts of alkali metals or alkalineearth metals. Alkali agents as provided herein are typically capable ofreacting with an unrefined petroleum acid (e.g., an acid in crude oil(reactive oil)) to form soap (a surfactant salt of a fatty acid) insitu. These in situ generated soaps serve as a source of surfactantscapable of reducing the interfacial tension of hydrocarbons with anaqueous composition. Examples of suitable alkali agents include, but arenot limited to, sodium hydroxide, potassium hydroxide, sodium carbonate,potassium carbonate, sodium silicate, sodium metaborate, and salts ofEDTA (e.g., EDTA tetrasodium salt or EDTA tetrapotassium salt). In oneembodiment, the alkali agent is NaOH. In other embodiments, the alkaliagent is Na₂CO₃.

In some embodiments, the aqueous pressure protection composition canhave a pH of at least 8 (e.g., at least 8.5, at least 9, at least 9.5,at least 10, at least 10.5, at least 11, or at least 11.5). In someembodiments, the aqueous pressure protection composition can have a pHof 12 or less (e.g., 11.5 or less, 11 or less, 10.5 or less, 10 or less,9.5 or less, 9 or less, or 8.5 or less).

The aqueous pressure protection composition can have a pH ranging fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the aqueous pressureprotection composition can have a pH of from 8 to 12 (e.g., from 8.5 to12, from 9 to 12, from 8.5 to 11.5, from 9 to 11.5, from 8.5 to 11, orfrom 9 to 11).

Co-Solvents

In some embodiments, the aqueous pressure protection composition cancomprise a co-solvent. The co-solvent can comprise any suitablewater-miscible solvent.

Suitable co-solvents include alcohols, such as lower carbon chainalcohols such as isopropyl alcohol, ethanol, n-propyl alcohol, n-butylalcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexylalcohol, sec-hexyl alcohol and the like; alcohol ethers, polyalkylenealcohol ethers, polyalkylene glycols, poly(oxyalkylene)glycols,poly(oxyalkylene)glycol ethers, ethoxylated phenol, or any other commonorganic co-solvent or combinations of any two or more co-solvents. Inone embodiment, the co-solvent can comprise alkyl ethoxylate (C1-C6)-XEOX=1-30 -linear or branched. In some embodiments, the co-solvent cancomprise ethylene glycol butyl ether (EGBE), diethylene glycol monobutylether (DGBE), triethylene glycol monobutyl ether (TEGBE), ethyleneglycol dibutyl ether (EGDE), polyethylene glycol monomethyl ether(mPEG), dimethyl ether, or any combination thereof. Examples of suitableco-solvents are also described in U.S. Pat. No. 10,337,303, which isincorporated by reference herein in its entirety.

In some embodiments, the co-solvent can be present in the aqueouspressure protection composition in an amount of from 0.1% to 25% byweight (e.g. from 0.1% to 10% by weight, or from 0.5% to 5% by weight)of the total weight of the aqueous pressure protection composition.

Viscosity-Modifying Polymers

In some embodiments, the aqueous pressure protection composition cancomprise a viscosity-modifying polymer.

Examples of viscosity-modifying polymer are known in the art. Examplesof suitable polymers include biopolymers such as polysaccharides. Forexample, polysaccharides can be xanthan gum, scleroglucan, guar gum, amixture thereof (e.g., any modifications thereof such as a modifiedchain), etc. Indeed, the terminology “mixtures thereof” or “combinationsthereof” can include “modifications thereof” herein. Examples ofsuitable synthetic polymers include polyacrylamides. Examples ofsuitable polymers include synthetic polymers such as partiallyhydrolyzed polyacrylamides (HPAMs or PHPAs) and hydrophobically-modifiedassociative polymers (APs). Also included are co-polymers ofpolyacrylamide (PAM) and one or both of 2-acrylamido 2-methylpropanesulfonic acid (and/or sodium salt) commonly referred to as AMPS (alsomore generally known as acrylamido tertiobutyl sulfonic acid or ATBS),N-vinyl pyrrolidone (NVP), and the NVP-based synthetic may be single-,co-, or ter-polymers. In one embodiment, the synthetic polymer ispolyacrylic acid (PAA). In one embodiment, the synthetic polymer ispolyvinyl alcohol (PVA). Copolymers may be made of any combination ormixture above, for example, a combination of NVP and ATBS.

In some embodiments, the viscosity-modifying polymer can be present inthe aqueous pressure protection composition in an amount of from 0.1% to25% by weight (e.g. from 0.1% to 10% by weight, or from 0.5% to 5% byweight) of the total weight of the aqueous pressure protectioncomposition.

Surfactant Packages

Suitable surfactant packages can comprise a primary surfactant andoptionally one or more secondary surfactants.

In some cases, the primary surfactant can comprise an anionicsurfactant. In these cases, one or more secondary surfactants cancomprise one or more non-ionic surfactants, one or more additionalanionic surfactants, one or more cationic surfactants, one or morezwitterionic surfactants, or any combination thereof.

In other cases, the primary surfactant can comprise a non-ionicsurfactant. In these cases, one or more secondary surfactants cancomprise one or more additional non-ionic surfactants, one or moreanionic surfactants, one or more cationic surfactants, one or morezwitterionic surfactants, or any combination thereof.

In other cases, the primary surfactant can comprise a cationicsurfactant. In these cases, one or more secondary surfactants cancomprise one or more non-ionic surfactants, one or more anionicsurfactants, one or more additional cationic surfactants, one or morezwitterionic surfactants, or any combination thereof.

In other cases, the primary surfactant can comprise a zwitterionicsurfactant. In these cases, one or more secondary surfactants cancomprise one or more non-ionic surfactants, one or more anionicsurfactants, one or more cationic surfactants, one or more additionalzwitterionic surfactants, or any combination thereof.

In some embodiments, the primary surfactant can comprise at least 10% byweight (e.g., at least 15% by weight, at least 20% by weight, at least25% by weight, at least 30% by weight, at least 35% by weight, at least40% by weight, at least 45% by weight, at least 50% by weight, at least55% by weight, at least 60% by weight, at least 65% by weight, at least70% by weight, at least 75% by weight, at least 80% by weight, or atleast 85% by weight) of the aqueous pressure protection composition,based on the total weight of the aqueous pressure protectioncomposition. In some embodiments, the primary surfactant can comprise90% by weight or less (e.g., 85% by weight or less, 80% by weight orless, 75% by weight or less, 70% by weight or less, 65% by weight orless, 60% by weight or less, 55% by weight or less, 50% by weight orless, 45% by weight or less, 40% by weight or less, 35% by weight orless, 30% by weight or less, 25% by weight or less, 20% by weight orless, or 15% by weight or less) of the aqueous pressure protectioncomposition, based on the total weight of the aqueous pressureprotection composition.

The primary surfactant can be present in the aqueous pressure protectioncomposition in an amount ranging from any of the minimum valuesdescribed above to any of the maximum values described above. Forexample, in some embodiments, the primary surfactant can comprise from10% to 90% by weight (e.g., from 10% to 50% by weight) of the aqueouspressure protection composition, based on the total weight of theaqueous pressure protection composition.

In some embodiments, the one or more secondary surfactants can compriseat least 10% by weight (e.g., at least 15% by weight, at least 20% byweight, at least 25% by weight, at least 30% by weight, at least 35% byweight, at least 40% by weight, at least 45% by weight, at least 50% byweight, at least 55% by weight, at least 60% by weight, at least 65% byweight, at least 70% by weight, at least 75% by weight, at least 80% byweight, or at least 85% by weight) of the aqueous pressure protectioncomposition, based on the total weight of the aqueous pressureprotection composition. In some embodiments, the one or more secondarysurfactants can comprise 90% by weight or less (e.g., 85% by weight orless, 80% by weight or less, 75% by weight or less, 70% by weight orless, 65% by weight or less, 60% by weight or less, 55% by weight orless, 50% by weight or less, 45% by weight or less, 40% by weight orless, 35% by weight or less, 30% by weight or less, 25% by weight orless, 20% by weight or less, or 15% by weight or less) of the aqueouspressure protection composition, based on the total weight of theaqueous pressure protection composition.

The one or more secondary surfactants can be present in the aqueouspressure protection composition in an amount ranging from any of theminimum values described above to any of the maximum values describedabove. For example, in some embodiments, the one or more secondarysurfactants can comprise from 10% to 90% by weight (e.g., from 10% to50% by weight) of the aqueous pressure protection composition, based onthe total weight of the aqueous pressure protection composition.

In some embodiments, the aqueous pressure protection composition cancomprise an anionic surfactant. In other embodiments, the aqueouspressure protection composition can consist essentially of an anionicsurfactant (i.e., the anionic surfactant is the only surfactant presentin the aqueous pressure protection composition). In other embodiments,the aqueous pressure protection composition can consist of an anionicsurfactant. In some of these embodiments, the aqueous pressureprotection composition further includes water. In some of theseembodiments, the aqueous pressure protection composition does notcomprise a hydrocarbon.

In some embodiments, the aqueous pressure protection composition cancomprise an anionic surfactant and a non-ionic surfactant. In otherembodiments, the aqueous pressure protection composition can consistessentially of an anionic surfactant and a non-ionic surfactant (i.e.,the anionic surfactant and the non-ionic surfactant are the onlysurfactants present in the aqueous pressure protection composition). Inother embodiments, the aqueous pressure protection composition canconsist of an anionic surfactant and a non-ionic surfactant. In some ofthese embodiments, the aqueous pressure protection composition furtherincludes water. In some of these embodiments, the aqueous pressureprotection composition does not comprise a hydrocarbon.

In some embodiments, the aqueous pressure protection composition cancomprise an anionic surfactant, a second anionic surfactant, and anon-ionic surfactant. In other embodiments, the aqueous pressureprotection composition can consist essentially of an anionic surfactant,a second anionic surfactant, and a non-ionic surfactant (i.e., theanionic surfactant, the second anionic surfactant, and the non-ionicsurfactant are the only surfactants present in the aqueous pressureprotection composition). In other embodiments, the aqueous pressureprotection composition can consist of an anionic surfactant, a secondanionic surfactant, and a non-ionic surfactant. In some of theseembodiments, the aqueous pressure protection composition furtherincludes water. In some of these embodiments, the aqueous pressureprotection composition does not comprise a hydrocarbon.

In some embodiments, the aqueous pressure protection composition cancomprise a non-ionic surfactant. In other embodiments, the aqueouspressure protection composition can consist essentially of a non-ionicsurfactant (i.e., the non-ionic surfactant is the only surfactantpresent in the aqueous pressure protection composition). In otherembodiments, the aqueous pressure protection composition can consist ofa non-ionic surfactant. In some of these embodiments, the aqueouspressure protection composition further includes water. In some of theseembodiments, the aqueous pressure protection composition does notcomprise a hydrocarbon.

In some embodiments, the aqueous pressure protection composition cancomprise a non-ionic surfactant, an anionic surfactant, and a secondanionic surfactant. In other embodiments, the aqueous pressureprotection composition can consist essentially of a non-ionicsurfactant, an anionic surfactant, and a second anionic surfactant(i.e., the anionic surfactant, the second anionic surfactant, and thenon-ionic surfactant are the only surfactants present in the aqueouspressure protection composition). In other embodiments, the aqueouspressure protection composition can consist of a non-ionic surfactant,an anionic surfactant, and a second anionic surfactant. In some of theseembodiments, the aqueous pressure protection composition furtherincludes water. In some of these embodiments, the aqueous pressureprotection composition does not comprise a hydrocarbon.

Suitable anionic surfactants for use as a primary surfactant and/or asecondary surfactant include a hydrophobic tail that comprises from 6 to60 carbon atoms. In some embodiments, the anionic surfactant can includea hydrophobic tail that comprises at least 6 carbon atoms (e.g., atleast 7 carbon atoms, at least 8 carbon atoms, at least 9 carbon atoms,at least 10 carbon atoms, at least 11 carbon atoms, at least 12 carbonatoms, at least 13 carbon atoms, at least 14 carbon atoms, at least 15carbon atoms, at least 16 carbon atoms, at least 17 carbon atoms, atleast 18 carbon atoms, at least 19 carbon atoms, at least 20 carbonatoms, at least 21 carbon atoms, at least 22 carbon atoms, at least 23carbon atoms, at least 24 carbon atoms, at least 25 carbon atoms, atleast 26 carbon atoms, at least 27 carbon atoms, at least 28 carbonatoms, at least 29 carbon atoms, at least 30 carbon atoms, at least 31carbon atoms, at least 32 carbon atoms, at least 33 carbon atoms, atleast 34 carbon atoms, at least 35 carbon atoms, at least 36 carbonatoms, at least 37 carbon atoms, at least 38 carbon atoms, at least 39carbon atoms, at least 40 carbon atoms, at least 41 carbon atoms, atleast 42 carbon atoms, at least 43 carbon atoms, at least 44 carbonatoms, at least 45 carbon atoms, at least 46 carbon atoms, at least 47carbon atoms, at least 48 carbon atoms, at least 49 carbon atoms, atleast 50 carbon atoms, at least 51 carbon atoms, at least 52 carbonatoms, at least 53 carbon atoms, at least 54 carbon atoms, at least 55carbon atoms, at least 56 carbon atoms, at least 57 carbon atoms, atleast 58 carbon atoms, or at least 59 carbon atoms). In someembodiments, the anionic surfactant can include a hydrophobic tail thatcomprises 60 carbon atoms or less (e.g., 59 carbon atoms or less, 58carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms or less,55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atoms orless, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbon atomsor less, 49 carbon atoms or less, 48 carbon atoms or less, 47 carbonatoms or less, 46 carbon atoms or less, 45 carbon atoms or less, 44carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms or less,41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atoms orless, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbon atomsor less, 35 carbon atoms or less, 34 carbon atoms or less, 33 carbonatoms or less, 32 carbon atoms or less, 31 carbon atoms or less, 30carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms or less,27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atoms orless, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbon atomsor less, 21 carbon atoms or less, 20 carbon atoms or less, 19 carbonatoms or less, 18 carbon atoms or less, 17 carbon atoms or less, 16carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms or less,13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atoms orless, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atoms orless, or 7 carbon atoms or less).

The anionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the anionic surfactant can comprise a hydrophobic tailcomprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60,from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32,from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16to 25, from 26 to 35, or from 36 to 45 carbon atoms. The hydrophobic(lipophilic) carbon tail may be a straight chain, branched chain, and/ormay comprise cyclic structures. The hydrophobic carbon tail may comprisesingle bonds, double bonds, triple bonds, or any combination thereof Insome embodiments, the anionic surfactant can include a branchedhydrophobic tail derived from Guerbet alcohols. The hydrophilic portionof the anionic surfactant can comprise, for example, one or more sulfatemoieties (e.g., one, two, or three sulfate moieties), one or moresulfonate moieties (e.g., one, two, or three sulfonate moieties), one ormore sulfosuccinate moieties (e.g., one, two, or three sulfosuccinatemoieties), one or more carboxylate moieties (e.g., one, two, or threecarboxylate moieties), or any combination thereof.

In some embodiments, the anionic surfactant can comprise, for example asulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, apolysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate,a carboxylate, a dicarboxylate, a polycarboxylate, or any combinationthereof. In some embodiments, the anionic surfactant can comprise, forexample a sulfonate, a disulfonate, a sulfate, a disulfate, asulfosuccinate, a disulfosuccinate, a carboxylate, a dicarboxylate, orany combination thereof. In some examples, the anionic surfactant cancomprise an internal olefin sulfonate (IOS), an isomerized olefinsulfonate, an alfa olefin sulfonate (AOS), an alkyl aryl sulfonate(AAS), a xylene sulfonate, an alkane sulfonate, a petroleum sulfonate,an alkyl diphenyl oxide (di)sulfonate, an alcohol sulfate, an alkoxysulfate, an alkoxy sulfonate, an alkoxy carboxylate, an alcoholphosphate, or an alkoxy phosphate. In some embodiments, the anionicsurfactant can comprise an alkoxy carboxylate surfactant, an alkoxysulfate surfactant, an alkoxy sulfonate surfactant, an alkyl sulfonatesurfactant, an aryl sulfonate surfactant, or an olefin sulfonatesurfactant.

An “alkoxy carboxylate surfactant” or “alkoxy carboxylate” refers to acompound having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —COO⁻ or acid or salt thereof includingmetal cations such as sodium. In embodiments, the alkoxy carboxylatesurfactant can be defined by the formulae below:

wherein R¹ is substituted or unsubstituted C6-C36 alkyl or substitutedor unsubstituted aryl; R² is, independently for each occurrence withinthe compound, hydrogen or unsubstituted C1-C6 alkyl; R³ is independentlyhydrogen or unsubstituted C1-C6 alkyl, n is an integer from 0 to 175, zis an integer from 1 to 6 and M⁺ is a monovalent, divalent or trivalentcation. In some of these embodiments, R¹ can be an unsubstituted linearor branched C6-C36 alkyl.

In certain embodiments, the alkoxy carboxylate can be aC6-C32:PO(0-65):EO(0-100)-carboxylate (i.e., a C6-C32 hydrophobic tail,such as a branched or unbranched C6-C32 alkyl group, attached to from 0to 65 propyleneoxy groups (—CH₂—CH(methyl)-O— linkers), attached in turnto from 0 to 100 ethyleneoxy groups (—CH₂—CH₂—O— linkers), attached inturn to —COO⁻ or an acid or salt thereof including metal cations such assodium). In certain embodiments, the alkoxy carboxylate can be abranched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate. Incertain embodiments, the alkoxy carboxylate can be a branched orunbranched C6-C12:PO(30-40):EO(25-35)-carboxylate. In certainembodiments, the alkoxy carboxylate can be a branched or unbranchedC6-C30:EO(8-30)-carboxylate.

An “alkoxy sulfate surfactant” or “alkoxy sulfate” refers to asurfactant having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium. In some embodiment, the alkoxy sulfatesurfactant has the formula R-(BO)_(e)-(PO)_(f)-(EO)_(g)-SO₃ ⁻ or acid orsalt (including metal cations such as sodium) thereof, wherein R isC6-C32 alkyl, BO is —CH₂—CH(ethyl)-O—, PO is —CH₂—CH(methyl)-O—, and EOis —CH₂—CH₂—O—. The symbols e, f and g are integers from 0 to 50 whereinat least one is not zero.

In embodiments, the alkoxy sulfate surfactant can be an aryl alkoxysulfate surfactant. The aryl alkoxy surfactant can be an alkoxysurfactant having an aryl attached to one or more alkoxylene groups(typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which,in turn is attached to —SO₃ ⁻ or acid or salt thereof including metalcations such as sodium.

An “alkyl sulfonate surfactant” or “alkyl sulfonate” refers to acompound that includes an alkyl group (e.g., a branched or unbranchedC6-C32 alkyl group) attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium.

An “aryl sulfate surfactant” or “aryl sulfate” refers to a compoundhaving an aryl group attached to —O—SO₃ ⁻ or acid or salt thereofincluding metal cations such as sodium. An “aryl sulfonate surfactant”or “aryl sulfonate” refers to a compound having an aryl group attachedto —SO₃ ⁻ or acid or salt thereof including metal cations such assodium. In some cases, the aryl group can be substituted, for example,with an alkyl group (an alkyl aryl sulfonate).

An “internal olefin sulfonate,” “isomerized olefin sulfonate,” or “IOS”refers to an unsaturated hydrocarbon compound comprising at least onecarbon-carbon double bond and at least one SO₃ ⁻ group, or a saltthereof. As used herein, a “C20-C28 internal olefin sulfonate,” “aC20-C28 isomerized olefin sulfonate,” or “C20-C28 IOS” refers to an IOS,or a mixture of IOSs with an average carbon number of 20 to 28, or of 23to 25. The C20-C28IOS may comprise at least 80% of IOS with carbonnumbers of 20 to 28, at least 90% of IOS with carbon numbers of 20 to28, or at least 99% of IOS with carbon numbers of 20 to 28. As usedherein, a “C15-C18 internal olefin sulfonate,” “C15-C18 isomerizedolefin sulfonate,” or “C15-C18 IOS” refers to an IOS or a mixture ofIOSs with an average carbon number of 15 to 18, or of 16 to 17. TheC15-C18 IOS may comprise at least 80% of IOS with carbon numbers of 15to 18, at least 90% of IOS with carbon numbers of 15 to 18, or at least99% of IOS with carbon numbers of 15 to 18. The internal olefinsulfonates or isomerized olefin sulfonates may be alpha olefinsulfonates, such as an isomerized alpha olefin sulfonate. The internalolefin sulfonates or isomerized olefin sulfonates may also comprisebranching. In certain embodiments, C15-18 IOS may be added to thesingle-phase liquid surfactant package when the LPS injection fluid isintended for use in high temperature unconventional subterraneanformations, such as formations above 130° F. (approximately 55° C.). TheIOS may be at least 20% branching, 30% branching, 40% branching, 50%branching, 60% branching, or 65% branching. In some embodiments, thebranching is between 20-98%, 30-90%, 40-80%, or around 65%. Examples ofinternal olefin sulfonates and the methods to make them are found inU.S. Pat. No. 5,488,148, U.S. Patent Application Publication2009/0112014, and SPE 129766, all incorporated herein by reference.

In embodiments, the anionic surfactant can be a disulfonate,alkyldiphenyloxide disulfonate, mono alkyldiphenyloxide disulfonate, dialkyldiphenyloxide disulfonate, or a di alkyldiphenyloxidemonosulfonate, where the alkyl group can be a C6-C36 linear or branchedalkyl group. In embodiments, the anionic surfactant can be analkylbenzene sulfonate or a dibenzene disufonate. In embodiments, theanionic surfactant can be benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt; linear or branched C6-C36alkyl:PO(0-65):EO(0-100) sulfate; or linear or branched C6-C36alkyl:PO(0-65):EO(0-100) carboxylate. In embodiments, the anionicsurfactant is an isomerized olefin sulfonate (C6-C30), internal olefinsulfonate (C6-C30) or internal olefin disulfonate (C6-C30). In someembodiments, the anionic surfactant is a Guerbet-PO(0-65)-E0(0-100)sulfate (Guerbet portion can be C6-C36). In some embodiments, theanionic surfactant is a Guerbet-PO(0-65)-EO(0-100) carboxylate (Guerbetportion can be C6-C36). In some embodiments, the anionic surfactant isalkyl PO(0-65) and EO(0-100) sulfonate: where the alkyl group is linearor branched C6-C36. In some embodiments, the anionic surfactant is asulfosuccinate, such as a dialkylsulfosuccinate. In some embodiments,the anionic surfactant is an alkyl aryl sulfonate (AAS) (e.g. an alkylbenzene sulfonate (ABS)), a C10-C30 internal olefin sulfate (IOS), apetroleum sulfonate, or an alkyl diphenyl oxide (di)sulfonate.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

R¹—R²—R³

wherein R¹ comprises a branched or unbranched, saturated or unsaturated,cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atomsand an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chaincomprising at least one oxide group selected from the group consistingof ethylene oxide, propylene oxide, butylene oxide, and combinationsthereof; and R³ comprises a branched or unbranched hydrocarbon chaincomprising 2-12 carbon atoms and from 2 to 5 carboxylate groups.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclicor non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and Mrepresents a counterion (e.g., Na⁺, K⁺). In some embodiments, R⁴ is abranched or unbranched, saturated or unsaturated, cyclic or non-cyclic,hydrophobic carbon chain having 6-16 carbon atoms.

Suitable non-ionic surfactants for use as a primary surfactant and/or asecondary surfactant include compounds that can be added to increasewettability. In embodiments, the hydrophilic-lipophilic balance (HLB) ofthe non-ionic surfactant is greater than 10 (e.g., greater than 9,greater than 8, or greater than 7). In some embodiments, the HLB of thenon-ionic surfactant is from 7 to 10.

The non-ionic surfactant can comprise a hydrophobic tail comprising from6 to 60 carbon atoms. In some embodiments, the non-ionic surfactant caninclude a hydrophobic tail that comprises at least 6 carbon atoms (e.g.,at least 7 carbon atoms, at least 8 carbon atoms, at least 9 carbonatoms, at least 10 carbon atoms, at least 11 carbon atoms, at least 12carbon atoms, at least 13 carbon atoms, at least 14 carbon atoms, atleast 15 carbon atoms, at least 16 carbon atoms, at least 17 carbonatoms, at least 18 carbon atoms, at least 19 carbon atoms, at least 20carbon atoms, at least 21 carbon atoms, at least 22 carbon atoms, atleast 23 carbon atoms, at least 24 carbon atoms, at least 25 carbonatoms, at least 26 carbon atoms, at least 27 carbon atoms, at least 28carbon atoms, at least 29 carbon atoms, at least 30 carbon atoms, atleast 31 carbon atoms, at least 32 carbon atoms, at least 33 carbonatoms, at least 34 carbon atoms, at least 35 carbon atoms, at least 36carbon atoms, at least 37 carbon atoms, at least 38 carbon atoms, atleast 39 carbon atoms, at least 40 carbon atoms, at least 41 carbonatoms, at least 42 carbon atoms, at least 43 carbon atoms, at least 44carbon atoms, at least 45 carbon atoms, at least 46 carbon atoms, atleast 47 carbon atoms, at least 48 carbon atoms, at least 49 carbonatoms, at least 50 carbon atoms, at least 51 carbon atoms, at least 52carbon atoms, at least 53 carbon atoms, at least 54 carbon atoms, atleast 55 carbon atoms, at least 56 carbon atoms, at least 57 carbonatoms, at least 58 carbon atoms, or at least 59 carbon atoms). In someembodiments, the non-ionic surfactant can include a hydrophobic tailthat comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less,58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms orless, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atomsor less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbonatoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less,44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms orless, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atomsor less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbonatoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less,30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms orless, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atomsor less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbonatoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less,16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms orless, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atomsor less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atomsor less, or 7 carbon atoms or less).

The non-ionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the non-ionic surfactant can comprise a hydrophobic tailcomprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60,from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32,from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16to 25, from 26 to 35, or from 36 to 45 carbon atoms. In some cases, thehydrophobic tail may be a straight chain, branched chain, and/or maycomprise cyclic structures. The hydrophobic carbon tail may comprisesingle bonds, double bonds, triple bonds, or any combination thereof Insome cases, the hydrophobic tail can comprise an alkyl group, with orwithout an aromatic ring (e.g., a phenyl ring) attached to it. In someembodiments, the hydrophobic tail can comprise a branched hydrophobictail derived from Guerbet alcohols.

Example non-ionic surfactants include alkyl aryl alkoxy alcohols, alkylalkoxy alcohols, or any combination thereof. In embodiments, thenon-ionic surfactant may be a mix of surfactants with different lengthlipophilic tail chain lengths. For example, the non-ionic surfactant maybe C9-C11:9EO, which indicates a mixture of non-ionic surfactants thathave a lipophilic tail length of 9 carbon to 11 carbon, which isfollowed by a chain of 9 EOs. The hydrophilic moiety is an alkyleneoxychain (e.g., an ethoxy (EO), butoxy (BO) and/or propoxy (PO) chain withtwo or more repeating units of EO, BO, and/or PO). In some embodiments,1-100 repeating units of EO are present. In some embodiments, 0-65repeating units of PO are present. In some embodiments, 0-25 repeatingunits of BO are present. For example, the non-ionic surfactant couldcomprise 10EO:5PO or 5EO. In embodiments, the non-ionic surfactant maybe a mix of surfactants with different length lipophilic tail chainlengths. For example, the non-ionic surfactant may be C9-C11:PO09:EO2,which indicates a mixture of non-ionic surfactants that have alipophilic tail length of 9 carbon to 11 carbon, which is followed by achain of 9 POs and 2 EOs. In specific embodiments, the non-ionicsurfactant is linear C9-C11:9EO. In some embodiments, the non-ionicsurfactant is a Guerbet PO(0-65) and EO(0-100) (Guerbet can be C6-C36);or alkyl PO(0-65) and EO(0-100): where the alkyl group is linear orbranched C1-C36. In some examples, the non-ionic surfactant can comprisea branched or unbranched C6-C32:PO(0-65):EO(0-100) (e.g., a branched orunbranched C6-C30:PO(30-40):EO(25-35), a branched or unbranchedC6-C12:PO(30-40):E0(25-35), a branched or unbranched C6-30:EO(8-30), orany combination thereof). In some embodiments, the non-ionic surfactantis one or more alkyl polyglucosides.

Example cationic surfactants include surfactant analogous to thosedescribed above, except bearing primary, secondary, or tertiary amines,or quaternary ammonium cations, as a hydrophilic head group.“Zwitterionic” or “zwitterion” as used herein refers to a neutralmolecule with a positive (or cationic) and a negative (or anionic)electrical charge at different locations within the same molecule.Example zwitterionic surfactants include betains and sultains.

Examples of suitable surfactants are disclosed, for example, in U.S.Pat. Nos. 3,811,504, 3,811,505, 3,811,507, 3,890,239, 4,463,806,6,022,843, 6,225,267, 7,629,299, 7,770,641, 9,976,072, 8,211, 837,9,422,469, 9,605,198, and 9,617,464; WIPO Patent Application Nos.WO/2008/079855, WO/2012/027757 and WO /2011/094442; as well as U.S.Patent Application Nos. 2005/0199395, 2006/0185845, 2006/0189486,2009/0270281, 2011/0046024, 2011/0100402, 2011/0190175, 2007/0191633,2010/004843. 2011/0201531, 2011/0190174, 2011/0071057, 2011/0059873,2011/0059872, 2011/0048721, 2010/0319920, 2010/0292110, and2017/0198202, each of which is hereby incorporated by reference hereinin its entirety for its description of example surfactants.

The primary surfactant can have a concentration within the aqueouspressure protection composition of at least 0.01% by weight (e.g., atleast 0.02% by weight, at least 0.03% by weight, at least 0.04% byweight, at least 0.05% by weight, at least 0.06% by weight, at least0.07% by weight, at least 0.08% by weight, at least 0.09% by weight, atleast 0.1% by weight, at least 0.15% by weight, at least 0.2% by weight,at least 0.25% by weight, at least 0.3% by weight, at least 0.35% byweight, at least 0.4% by weight, at least 0.45% by weight, at least 0.5%by weight, at least 0.55% by weight, at least 0.6% by weight, at least0.65% by weight, at least 0.7% by weight, at least 0.75% by weight, atleast 0.8% by weight, at least 0.85% by weight, at least 0.9% by weight,at least 0.95% by weight, at least 1% by weight, at least 1.25% byweight, at least 1.5% by weight, at least 1.75% by weight, at least 2%by weight, or at least 2.25% by weight), based on the total weight ofthe aqueous pressure protection composition. In some embodiments, theprimary surfactant can have a concentration within the aqueous pressureprotection composition of 2.5% by weight or less (e.g., 2.25% by weightor less, 2% by weight or less, 1.75% by weight or less, 1.5% by weightor less, 1.25% by weight or less, 1% by weight or less, 0.95% by weightor less, 0.9% by weight or less, 0.85% by weight or less, 0.8% by weightor less, 0.75% by weight or less, 0.7% by weight or less, 0.65% byweight or less, 0.6% by weight or less, 0.55% by weight or less, 0.5% byweight or less, 0.45% by weight or less, 0.4% by weight or less, 0.35%by weight or less, 0.3% by weight or less, 0.25% by weight or less, 0.2%by weight or less, 0.15% by weight or less, 0.1% by weight or less,0.09% by weight or less, 0.08% by weight or less, 0.07% by weight orless, 0.06% by weight or less, 0.05% by weight or less, 0.04% by weightor less, 0.03% by weight or less, or 0.02% by weight or less), based onthe total weight of the aqueous pressure protection composition. Inparticular embodiments, the primary surfactant can have a concentrationwithin the aqueous pressure protection composition of less than 1%, lessthan 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, or lessthan 0.05%.

The primary surfactant can have a concentration within the aqueouspressure protection composition ranging from any of the minimum valuesdescribed above to any of the maximum values described above. Forexample, in some embodiments, the primary surfactant can have aconcentration within the aqueous pressure protection composition of from0.01% to 2.5% by weight (e.g., from 0.05% to 0.5% by weight), based onthe total weight of the aqueous pressure protection composition.

When present, the one or more secondary surfactants can have aconcentration within the aqueous pressure protection composition of atleast 0.001% by weight (e.g., at least 0.005% by weight, at least 0.01%by weight, at least 0.02% by weight, at least 0.03% by weight, at least0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, atleast 0.07% by weight, at least 0.08% by weight, at least 0.09% byweight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2%by weight, at least 0.25% by weight, at least 0.3% by weight, at least0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, atleast 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight,at least 0.65% by weight, at least 0.7% by weight, at least 0.75% byweight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9%by weight, at least 0.95% by weight, at least 1% by weight, at least1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, atleast 2% by weight, or at least 2.25% by weight), based on the totalweight of the aqueous pressure protection composition. In someembodiments, the one or more secondary surfactants can have aconcentration within the aqueous pressure protection composition of 2.5%by weight or less (e.g., 2.25% by weight or less, 2% by weight or less,1.75% by weight or less, 1.5% by weight or less, 1.25% by weight orless, 1% by weight or less, 0.95% by weight or less, 0.9% by weight orless, 0.85% by weight or less, 0.8% by weight or less, 0.75% by weightor less, 0.7% by weight or less, 0.65% by weight or less, 0.6% by weightor less, 0.55% by weight or less, 0.5% by weight or less, 0.45% byweight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3% byweight or less, 0.25% by weight or less, 0.2% by weight or less, 0.15%by weight or less, 0.1% by weight or less, 0.09% by weight or less,0.08% by weight or less, 0.07% by weight or less, 0.06% by weight orless, 0.05% by weight or less, 0.04% by weight or less, 0.03% by weightor less, 0.02% by weight or less, 0.01% by weight or less, or 0.005% byweight or less), based on the total weight of the aqueous pressureprotection composition. In particular embodiments, the one or moresecondary surfactants can have a concentration within the aqueouspressure protection composition of less than 2%, less than 1.5%, lessthan 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than0.075%, less than 0.05%, or less than 0.01%.

When present, the one or more secondary surfactants can have aconcentration within the aqueous pressure protection composition rangingfrom any of the minimum values described above to any of the maximumvalues described above. For example, in some embodiments, the one ormore secondary surfactants can have a concentration within the aqueouspressure protection composition of from 0.001% to 2.5% by weight (e.g.,from 0.001% to 1.5% by weight, or from 0.05% to 0.5% by weight), basedon the total weight of the aqueous pressure protection composition.

In some embodiments, the primary surfactant and one or more secondarysurfactants can be present in the aqueous pressure protectioncomposition at a weight ratio of primary surfactant to one or moresecondary surfactants of at least 1:1 (e.g., at least 2:1, at least2.5:1, at least 3:1, at least 4:1, at least 5:1, at least 6:1, at least7:1, at least 8:1, or at least 9:1). In some embodiments, the primarysurfactant and one or more secondary surfactants can be present in theaqueous pressure protection composition in a weight ratio of primarysurfactant to one or more secondary surfactants of 10:1 or less (e.g.,9:1 or less; 8:1 or less, 7:1 or less, 6:1 or less, 5:1 or less, 4:1 orless, 3:1 or less, 2.5:1 or less, or 2:1 or less).

The primary surfactant and one or more secondary surfactants can bepresent in the aqueous pressure protection composition in a weight ratioranging from any of the minimum values described above to any of themaximum values described above. For example, the primary surfactant andone or more secondary surfactants can be present in the aqueous pressureprotection composition in a weight ratio of primary surfactant to one ormore secondary surfactants of from 1:1 to 10:1 (e.g., 1:1 to 5:1).

In other embodiments, the one or more secondary surfactants are absent(i.e., the primary surfactant is the only surfactant present in theaqueous pressure protection composition).

In some embodiments, the total concentration of all surfactants in theaqueous pressure protection composition (the total concentration of theprimary surfactant and the one or more secondary surfactants in theaqueous pressure protection composition) can be at least 0.01% by weight(e.g., at least 0.02% by weight, at least 0.03% by weight, at least0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, atleast 0.07% by weight, at least 0.08% by weight, at least 0.09% byweight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2%by weight, at least 0.25% by weight, at least 0.3% by weight, at least0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, atleast 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight,at least 0.65% by weight, at least 0.7% by weight, at least 0.75% byweight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9%by weight, at least 0.95% by weight, at least 1% by weight, at least1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, atleast 2% by weight, at least 2.25% by weight, at least 2.5% by weight,at least 2.75% by weight, at least 3% by weight, at least 3.25% byweight, at least 3.5% by weight, at least 3.75% by weight, at least 4%by weight, at least 4.25% by weight, at least 4.5% by weight, or atleast 4.75% by weight), based on the total weight of the aqueouspressure protection composition. In some embodiments, the totalconcentration of all surfactants in the aqueous pressure protectioncomposition (the total concentration of the primary surfactant and theone or more secondary surfactants in the aqueous pressure protectioncomposition) can be 5% by weight or less (e.g., 4.75% by weight or less,4.5% by weight or less, 4.25% by weight or less, 4% by weight or less,3.75% by weight or less, 3.5% by weight or less, 3.25% by weight orless, 3% by weight or less, 2.75% by weight or less, 2.5% by weight orless, 2.25% by weight or less, 2% by weight or less, 1.75% by weight orless, 1.5% by weight or less, 1.25% by weight or less, 1% by weight orless, 0.95% by weight or less, 0.9% by weight or less, 0.85% by weightor less, 0.8% by weight or less, 0.75% by weight or less, 0.7% by weightor less, 0.65% by weight or less, 0.6% by weight or less, 0.55% byweight or less, 0.5% by weight or less, 0.45% by weight or less, 0.4% byweight or less, 0.35% by weight or less, 0.3% by weight or less, 0.25%by weight or less, 0.2% by weight or less, 0.15% by weight or less, 0.1%by weight or less, 0.09% by weight or less, 0.08% by weight or less,0.07% by weight or less, 0.06% by weight or less, 0.05% by weight orless, 0.04% by weight or less, 0.03% by weight or less, or 0.02% byweight or less), based on the total weight of the aqueous pressureprotection composition.

The total concentration of all surfactants in the aqueous pressureprotection composition (the total concentration of the primarysurfactant and the one or more secondary surfactants in the aqueouspressure protection composition) can range from any of the minimumvalues described above to any of the maximum values described above. Forexample, in some embodiments, the total concentration of all surfactantsin the aqueous pressure protection composition (the total concentrationof the primary surfactant and the one or more secondary surfactants inthe aqueous pressure protection composition) can be from 0.01% by weightto 5% by weight (e.g., from 0.01% to 2.5% by weight, from 0.01% to 1% byweight, or from 0.01% to 0.5% by weight).

In some embodiments when the aqueous pressure protection composition isbeing injected into a horizontal well, the total concentration of allsurfactants in the aqueous pressure protection composition (the totalconcentration of the primary surfactant and the one or more secondarysurfactants in the aqueous pressure protection composition) can be from0.01% to 1.5% by weight, from 0.01% to 1% by weight, or from 0.01% to0.5% by weight.

In some embodiments when the aqueous pressure protection composition isbeing injected into a vertical well, the total concentration of allsurfactants in the aqueous pressure protection composition (the totalconcentration of the primary surfactant and the one or more secondarysurfactants in the aqueous pressure protection composition) can be from0.01% to 5% by weight, from 0.01% to 1% by weight, from 0.5% to 5% byweight, from 0.5% to 2.5% by weight, from 0.5% to 1.5% by weight, from0.5% to 1% by weight, from 1% to 5% by weight, from 1% to 2.5% byweight, or from 1% to 1.5% by weight.

In some embodiments, the aqueous pressure protection composition cancomprise a non-ionic surfactant and an anionic surfactant (e.g., asulfonate or disulfonate). In some embodiments, the aqueous pressureprotection composition can comprise a non-ionic surfactant and two ormore anionic surfactants (e.g., a sulfonate or disulfonate and acarboxylate). In some embodiments, the aqueous pressure protectioncomposition can comprise a non-ionic surfactant (e.g., a C6-C16 alkylphenol ethoxylate, or a C6-C16:PO(0-25):EO(0-25), such as a C9-C11ethoxylated alcohol, a C13 ethoxylated alcohol, a C6-C10 ethoxylatedpropoxylated alcohol, or a C10-C14 ethoxylated Guerbet alcohol) and asulfonate surfactant (e.g., a C10-16 disulfonate, or a C16-28 IOS). Insome embodiments, the aqueous pressure protection composition cancomprise a non-ionic surfactant (e.g., a C6-C16 alkyl phenol ethoxylate,or a C6-16:PO(0-25):EO(0-25), such as a C9-C11 ethoxylated alcohol, aC13 ethoxylated alcohol, a C6-C10 ethoxylated propoxylated alcohol, or aC10-C14 ethoxylated Guerbet alcohol), a sulfonate surfactant (e.g., aC10-16 disulfonate, or a C16-28 IOS), and a carboxylate surfactant(e.g., a C10-16 alkyl polyglucoside carboxylate or a C22-C36 Guerbetalkoxylated carboxylate).

Specific example embodiments include the aqueous pressure protectioncompositions in the table below (as well as aqueous pressure protectioncomposition containing the surfactant packages shown in the tablebelow).

Surfactants and Co-Surfactants in Surfactant Package Example (in weightpercent) 1 0.09% alkoxylated C6-C16 alcohol 0.06% disulfonate 2 0.1%alkoxylated C6-C16 alcohol 0.1% carboxylate 0.1% disulfonate 3 0.15%alkoxylated C6-C16 alcohol 0.075% carboxylate 0.075% disulfonate 4 0.2%alkoxylated C6-C16 alcohol 0.1% carboxylate 5 0.2% alkoxylated C6-C16alcohol 0.033% carboxylate 0.066% disulfonate 6 0.2% alkoxylated C6-C16alcohol 0.033% carboxylate 0.066% disulfonate 7 0.2% alkoxylated C6-C16alcohol 0.05% carboxylate 0.05% olefin sulfonate 8 0.15% alkoxylatedC6-C16 alcohol 0.05% carboxylate 0.05% olefin sulfonate 0.05% alkylpolyglucoside 9 0.1% alkoxylated C6-C16 alcohol 0.05% carboxylate 0.05%olefin sulfonate 0.1% alkyl polyglucoside 10 0.15% alkoxylated C6-C16alcohol 0.07% carboxylate 0.03% olefin sulfonate 0.1% alkylpolyglucoside 11 0.1% alkoxylated C6-C16 alcohol 0.04% carboxylate 0.05%olefin sulfonate 0.03% disulfonate 0.1% alkyl polyglucoside 12 0.1%alkoxylated C6-C16 alcohol 0.04% carboxylate 0.06% disulfonate 0.1%alkyl polyglucoside 13 0.15% alkoxylated C6-C16 alcohol 0.15%alkoxylated alkylphenol 0.1% olefin sulfonate 0.1% Guerbet alkoxylatedcarboxylate 14 0.125% alkoxylated C6-C16 alcohol 0.175% alkoxylatedalkylphenol 0.1% olefin sulfonate 0.1% Guerbet alkoxylated carboxylate15 0.1% alkoxylated C6-C16 alcohol 0.2% alkoxylated alkylphenol 0.1%olefin sulfonate 0.1% Guerbet alkoxylated carboxylate 16 0.12%alkoxylated C6-C16 alcohol 0.22% alkoxylated alkylphenol 0.08% olefinsulfonate 0.08% Guerbet alkoxylated carboxylate 17 0.15% alkoxylatedC6-C16 alcohol 0.15% alkoxylated alkylphenol 0.08% olefin sulfonate0.06% Guerbet alkoxylated carboxylate 0.06% carboxylate 18 0.15%alkoxylated C6-C16 alcohol 0.15% alkoxylated alkylphenol 0.05% olefinsulfonate 0.1% Guerbet alkoxylated carboxylate 0.05% disulfonate 19 0.5%olefin sulfonate 0.5% Guerbet alkoxylated carboxylate 0.55% glycosidesor glucosides 20 0.5% olefin sulfonate 0.5% Guerbet alkoxylatedcarboxylate 0.5% glycosides or glucosides 0.25% alkoxylated C6-C16alcohol 21 0.5% olefin sulfonate 0.5% Guerbet alkoxylated carboxylate0.5% glycosides or glucosides 0.5% alkoxylated C6-C16 alcohol 22 0.5%olefin sulfonate 0.5% Guerbet alkoxylated carboxylate 1% glycosides orglucosides 0.5% alkoxylated C6-C16 alcohol 23 0.05% olefin sulfonate0.05% Guerbet alkoxylated carboxylate 0.05% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 24 0.075% glycosides or glucosides0.075% alkoxylated C6-C16 alcohol 25 0.1% alkoxylated C6-C16 alcohol0.05% disulfonate 26 0.1% alkoxylated C6-C16 alcohol 0.05% disulfonate0.03% hydroxyalkyl alkylammonium chloride 27 0.03% olefin sulfonate0.04% Guerbet alkoxylated carboxylate 0.08% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 28 0.4% olefin sulfonate 0.4% Guerbetalkoxylated carboxylate 0.7% glycosides or glucosides 0.5% alkoxylatedC6-C16 alcohol 29 0.05% olefin sulfonate 0.1% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 30 0.05% olefin sulfonate 0.1% alkylpolyglucoside 0.05% alkoxylated C6-C16 alcohol 31 0.05% olefin sulfonate0.1% glycosides or glucosides 0.05% alkoxylated C6-C16 alcohol 32 0.05%olefin sulfonate 0.1% alkyl polyglucoside 0.05% alkoxylated C6-C16alcohol 33 0.05% olefin sulfonate 0.1% alkyl polyglucoside 0.05%alkoxylated C6-C16 alcohol 34 0.05% olefin sulfonate 0.05% glycosides orglucosides 0.05% alkoxylated C6-C16 alcohol 0.05% carboxylate 35 0.05%olefin sulfonate 0.05% glycosides or glucosides 0.05% alkoxylated C6-C16alcohol 0.05% carboxylate 36 0.05% olefin sulfonate 0.05% alkylpolyglucoside 0.05% alkoxylated C6-C16 alcohol 37 0.06% olefin sulfonate0.05% alkyl polyglucoside 0.04% alkoxylated C6-C16 alcohol 38 0.04%olefin sulfonate 0.08% glycosides or glucosides 0.05% alkoxylated C6-C16alcohol 0.03% disulfonate 39 0.035% olefin sulfonate 0.075% glycosidesor glucosides 0.05% alkoxylated C6-C16 alcohol 0.04% disulfonate 400.035% olefin sulfonate 0.07% glycosides or glucosides 0.045%alkoxylated C6-C16 alcohol 0.05% disulfonate 41 0.1% alkoxylated C6-C16alcohol 0.1% disulfonate 42 0.25% Guerbet alkoxylated carboxylate 0.25%olefin sulfonate 0.5% glycosides or glucosides 0.5% co-solvent 43 0.075%alkoxylated C12-C22 alcohol 0.075% disulfonate 44 0.075% alkoxylatedC6-C16 Guerbet alcohol 0.075% disulfonate 45 0.075% alkoxylated C12-C22Guerbet alcohol 0.075% disulfonate 46 0.075% alkoxylated C6-C16 alcohol0.075% disulfonate 47 0.075% disulfonate 0.075% alkoxylated C6-C16alcohol 48 0.0625% disulfonate 0.0875% alkoxylated C6-C16 alcohol 490.055% disulfonate 0.095% alkoxylated C6-C16 alcohol 50 0.075%disulfonate 0.075% alkoxylated C6-C16 alcohol 51 1% alkoxylated C6-C16alcohol 0.5% disulfonate 52 1% alkoxylated C6-C16 alcohol 53 1%alkoxylated C6-C16 alcohol 2.25% sulfosuccinate 54 0.25% Guerbetalkoxylated carboxylate 1% alkoxylated C6-C16 alcohol 2.25%sulfosuccinate 55 0.25% Guerbet alkoxylated carboxylate 1% alkoxylatedalkylphenol 2.25% sulfosuccinate 56 0.25% Guerbet alkoxylatedcarboxylate 1% alkoxylated C6-C16 alcohol 57 0.25 Guerbet alkoxylatedcarboxylate 1% alkoxylated alkylphenol 58 0.65% carboxylate 0.35%alkoxylated C6-C16 alcohol 59 0.325% carboxylate 0.925% alkoxylatedC6-C16 alcohol 60 0.25% olefin sulfonate 1.0% alkoxylated C6-C16 alcohol61 0.15% olefin sulfonate 0.2% Guerbet alkoxylated carboxylate 0.92%carboxylate 62 0.65% carboxylate 0.35% second carboxylate 63 0.65%carboxylate 0.35% alkoxylated C6-C16 alcohol 1% olefin sulfonate 64 1%alkoxylated alcohol 1% olefin sulfonate 65 0.5% alkoxylated alcohol 0.5%olefin sulfonate 0.25% carboxylate 66 0.6% co-solvent 0.6% olefinsulfonate 67 0.6% co-solvent 0.3% disulfonate 0.3% olefin sulfonate 680.6% Guerbet alkoxylated carboxylate 0.6% disulfonate 69 0.6% co-solvent0.4% disulfonate 0.2% olefin sulfonate 70 0.5% alkoxylated C6-C16alcohol 0.4% disulfonate 0.3% olefin sulfonate 71 1% alkoxylated C6-C16alcohol 72 0.9% alkoxylated C6-C16 alcohol 0.6% disulfonate 73 0.4%alkoxylated C6-C16 alcohol 0.35% disulfonate 0.25% olefin sulfonate 0.5%co-solvent 74 0.25% Guerbet alkoxylated carboxylate 0.5% alkoxylatedC6-C16 alcohol 0.35% disulfonate 0.15% olefin sulfonate 0.35% co-solvent75 0.25% Guerbet alkoxylated carboxylate 0.25% alkoxylated C6-C16alcohol 0.25% olefin sulfonate 0.25% co-solvent 76 0.25% Guerbetalkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.25% olefinsulfonate 0.25% alkoxylated alcohol 77 0.25% Guerbet alkoxylatedcarboxylate 0.35% olefin sulfonate 0.5% alkoxylated alcohol 78 0.25%Guerbet alkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.15%olefin sulfonate 0.1% disulfonate 0.25% co-solvent 79 0.25% Guerbetalkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.25% olefinsulfonate 0.25% glycosides or glucosides 0.25% co-solvent 0.15%disulfonate 80 0.25% Guerbet alkoxylated carboxylate 0.25% olefinsulfonate 0.5% glycosides or glucosides 0.25% co-solvent 81 0.15%alkoxylated C12-C22 alcohol 82 0.075% disulfonate 0.075% alkoxylatedC12-C22 alcohol 83 0.75% alkoxylated C12-C22 alcohol 0.75% disulfonate84 0.075% alkoxylated C12-C22 alcohol 0.075% alkoxylated C6-C16 Guerbetalcohol 85 0.15% alkoxylated C6-C16 Guerbet alcohol 86 0.075%disulfonate 0.075% alkoxylated C6-C16 Guerbet alcohol 87 0.075%alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 0.05% co-solvent88 0.1% alkoxylated C6-C16 alcohol 0.05% disulfonate 89 1% alkoxylatedC6-C16 alcohol 0.5% disulfonate 90 0.075% alkoxylated C6-C16 Guerbetalcohol 0.075% disulfonate 91 0.075% alkoxylated C6-C16 Guerbet alcohol0.125% disulfonate 92 0.075% alkoxylated C12-C22 alcohol 0.125%disulfonate 93 0.75% disulfonate 0.75% alkoxylated C12-C22 alcohol 940.75% alkoxylated C6-C16 Guerbet alcohol 0.75% disulfonate 95 0.1%alkoxylated C6-C16 Guerbet alcohol 0.05% disulfonate 96 0.75%disulfonate 0.75% alkoxylated C6-C16 Guerbet alcohol 97 0.75%alkoxylated C6-C16 alcohol 0.75% disulfonate 98 0.75% disulfonate 0.75%alkoxylated C6-C16 alcohol 99 0.1% alkoxylated C6-C16 alcohol 0.05%disulfonate 100 0.09% alkoxylated C6-C16 alcohol 0.06% disulfonate 1010.1% alkoxylated C6-C16 alcohol 0.1% disulfonate 0.1% Guerbetalkoxylated carboxylate 102 0.1% alkoxylated C6-C16 alcohol 0.1%disulfonate 103 0.65% Guerbet alkoxylated carboxylate 0.35% olefinsulfonate 0.33% alkoxylated alkylphenol 0.5% co-solvent 0.25% secondco-solvent 104 0.075% alkoxylated C6-C16 alcohol 0.075% benzenesulfonicacid, decyl(sulfophenoxy)-disodium salt 105 0.15% alkoxylated C6-C16alcohol 0.05% benzenesulfonic acid, decyl(sulfophenoxy)-disodium salt106 0.9% Guerbet alkoxylated carboxylate 0.9% alkoxylated C6-C16 alcohol1.2% olefin sulfonate 0.225% co-solvent 2% sodium tetraborate 1% aceticacid 107 1% alkoxylated C6-C16 alcohol 1% olefin sulfonate 2% sodiumtetraborate 1% acetic acid 108 1% alkoxylated C6-C16 alcohol 0.75%olefin sulfonate 0.5% disulfonate 2% sodium tetraborate 1% acetic acid109 1% alkoxylated C6-C16 alcohol 0.75% olefin sulfonate 0.3%disulfonate 2% sodium tetraborate 1% acetic acid 110 0.5% alkoxylatedC6-C16 alcohol 0.85% olefin sulfonate 0.15% disulfonate 2% sodiumtetraborate 1% acetic acid 111 0.9% Guerbet alkoxylated carboxylate 0.9%alkoxylated C6-C16 alcohol 1.2% olefin sulfonate 0.225% co-solvent 2%sodium tetraborate 1% citric acid 112 1% alkoxylated C6-C16 alcohol0.75% olefin sulfonate 0.3% disulfonate 2% sodium tetraborate 1% citricacid 113 0.9% Guerbet alkoxylated carboxylate 0.9% alkoxylated C6-C16alcohol 1.2% olefin sulfonate 0.225% co-solvent 2% sodium tetraborate1.1% citric acid 114 0.5% Guerbet alkoxylated carboxylate 0.25% C6-C16alcohol alkoxylated carboxylate 0.5% alkoxylated C6-C16 alcohol 0.5%olefin sulfonate 0.1% disulfonate 0.5% co-solvent 2% sodium tetraborate1% acetic acid 115 0.5% C6-C16 alcohol alkoxylated carboxylate 0.25%alkoxylated C6-C16 alcohol 0.15% olefin sulfonate 0.35% disulfonate 2%sodium tetraborate 1% acetic acid 116 0.5% Guerbet alkoxylatedcarboxylate 0.25% C6-C16 alcohol alkoxylated carboxylate 0.5%alkoxylated C6-C16 alcohol 0.5% olefin sulfonate 0.1% disulfonate 0.5%co-solvent 0.02% cetyl betaine 2% sodium tetraborate 1% acetic acid

In some embodiments, the one or more surfactants in the aqueous pressureprotection composition can decrease the interfacial tension (IFT) of theaqueous pressure protection composition with hydrocarbons in thereservoir. Reducing the IFT can decrease pressure required to drive theaqueous pressure protection composition into the formation matrix. Inaddition, decreasing the IFT reduces water block during production,facilitating the flow of hydrocarbons from the formation to the wellbore(e.g., facilitating the flow of hydrocarbons back through the fracturesand to the wellbore). In this way, hydrocarbon recovery can befacilitated by the one or more surfactants in the aqueous pressureprotection composition.

In some embodiments, the one or more surfactants in the aqueous pressureprotection composition can change the wettability of the reservoir. Inparticular, in embodiments where the reservoir is oil-wet or mixed-wet,the one or more surfactants in the aqueous pressure protectioncomposition can make the reservoir more water-wet. By increasing thewater-wetness of the reservoir, the formation will imbibe injectedaqueous pressure protection composition into the formation matrix,leading to a corresponding flow of hydrocarbon from regions within theformation back to the fractures. In this way, hydrocarbon recovery canbe facilitated by the one or more surfactants in the aqueous pressureprotection composition.

Nanoparticles

In some embodiments, the aqueous pressure protection compositions cancomprise nanoparticles. The nanoparticles can comprise any of thecomponent of the aqueous pressure protection compositions describedherein. For example, the nanoparticles can comprise surfactant package(or one or more components thereof, an acid, an alkali agent, aco-solvent, a viscosity-modifying polymer, or any combination thereof).The nanoparticles can also comprise additional additives suitable forincorporation in the aqueous pressure protection compositions, such as achelating agent (e.g., EDTA or a salt thereof, to reduce formationdamage), a clay swelling inhibitor (e.g., KCl, to improve injectionefficiency), a biocide, a scale inhibitor, an anti-foam agent (e.g.,chemical defoamer), a corrosion inhibitor, or any combination thereof.Other examples of suitable nanoparticles are described, for example, inU.S. Pat. No. 10,266,750, which is hereby incorporated by reference inits entirety.

Foamed Pressure Protection Compositions

Also provided are analogous pressure protection methods which employfoamed pressure protection compositions. For example, in someembodiments, a foam can be injected into the existing wellbore toprovide pressure protection to the existing wellbore prior to fracturinga new wellbore proximate to the existing wellbore. The foam can compriseany suitable foam known for use in oil and gas operations. The foam canbe formed using any suitable expansion gas as discussed in detail below,such as, for example, air, helium, carbon dioxide, nitrogen, natural gasor a hydrocarbon component thereof, or any combination thereof.

Accordingly, also provided are methods for pressure protection of anexisting wellbore that has previously been fractured in proximity to anew wellbore to be fractured that comprise (a) injecting a foamedpressure protection composition into the unconventional subterraneanformation via an existing wellbore in fluid communication with a rockmatrix of the unconventional subterranean formation prior to and/orduring injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. As discussed above with respect to aqueouspressure protection compositions, the foamed pressure protectionsolution can be injected at a pressure and flowrate effective toincrease the existing wellbore pressure without substantiallyrefracturing the existing wellbore. All of these methods can beanalogously performed using foamed compositions.

The foam can be produced on the surface (above ground) or downhole(e.g., bottom hole using methods known in the art for artificial liftoperations). Accordingly, in some embodiments, step (a) can comprisecombining a foam precursor solution with an expansion gas to form thefoamed pressure protection composition above ground, and injecting thefoamed pressure protection composition into the existing wellbore. Inother embodiments, step (a) can comprise combining a foam precursorsolution with an expansion gas downhole to form the foamed pressureprotection composition in situ within the existing wellbore.

In some embodiments, the foamed pressure protection composition can havea viscosity of at least 1.5 cP at 25° C., such as a viscosity of atleast 5 cP at 25° C. In some embodiments, the the foamed pressureprotection composition can have a viscosity of from 1.5 cP to 50,000 cPat 25° C., such as a viscosity of from 5 cP to 50,000 cP at 25° C.

The foamed pressure protection composition can comprise a surfactantpackage comprising a primary foaming surfactant. The primary foamingsurfactant can comprise, for example, an anionic surfactant, azwitterionic surfactant, an amphoteric surfactant, a cationicsurfactant, or a non-ionic surfactant. In certain embodiments, theprimary foaming surfactant can comprise an anionic surfactant, azwitterionic surfactant, or an amphoteric surfactant. Optionally, thesurfactant package can further comprise one or more secondarysurfactants. The one or more secondary surfactants comprise one or moreanionic surfactants, one or more cationic surfactants, one or morenon-ionic surfactants, one or more zwitterionic surfactants, one or moreamphoterics, one or more fluorinated surfactants, or any combinationthereof. Examples of suitable surfactants (and combinations ofsurfactants) are described above with respect to the surfactant packagesthat can be incorporated in the aqueous pressure protection compositionsdescribed herein.

In some embodiments, the foamed pressure protection composition cancomprise from 30% to 98% expansion gas, such as from 50% to 98%expansion gas. The expansion gas can comprise, for example, air, helium,carbon dioxide, nitrogen, natural gas or a hydrocarbon componentthereof, or any combination thereof.

In certain embodiments, the foamed pressure protection compositions canbe substantially free of proppant particles.

Optionally, the foamed pressure protection compositions can comprise aviscosity-modifying polymer. Examples of viscosity-modifying polymersare known in the art. Examples of suitable polymers include biopolymerssuch as polysaccharides. For example, polysaccharides can be xanthangum, guar gum, a scleroglucan, a schizophyllan, HEC, a mixture thereof(e.g., any modifications thereof such as a modified chain), etc. Indeed,the terminology “mixtures thereof” or “combinations thereof” can include“modifications thereof” herein. Examples of suitable synthetic polymersinclude polyacrylamides. Examples of suitable polymers include syntheticpolymers such as partially hydrolyzed polyacrylamides (HPAMs or PHPAs)and hydrophobically-modified associative polymers (APs). Also includedare co-polymers of polyacrylamide (PAM) and one or both of 2-acrylamido2-methylpropane sulfonic acid (and/or sodium salt) commonly referred toas AMPS (also more generally known as acrylamido tertiobutyl sulfonicacid or ATBS), N-vinyl pyrrolidone (NVP), and the NVP-based syntheticmay be single-, co-, or ter-polymers. In one embodiment, the syntheticpolymer is polyacrylic acid (PAA). In one embodiment, the syntheticpolymer is polyvinyl alcohol (PVA). Copolymers may be made of anycombination or mixture above, for example, a combination of NVP andATBS.

In some embodiments, the foamed pressure protection composition cancomprise a foam stabilizer. Examples of foam stabilizers includecrosslinkers (e.g., a borate crosslinking agent, a Zr crosslinkingagent, a Ti crosslinking agent, an Al crosslinking agent, an organiccrosslinker, or any combination thereof), particulate stabilizers (e.g.,nanoparticles or microparticles comprising, for example, nickel oxide,alumina, silica (surface-modified), a silicate, iron oxide (Fe₃O₄),titanium oxide, impregnated nickel on alumina, synthetic clay, naturalclay, iron zinc sulfide, magnetite, iron octanoate, or any combinationthereof), or combinations thereof.

Foamed pressure protection compositions can further include any of thecomponents described above with respect to aqueous pressure protectioncompositions. For example, foamed pressure protection compositions canalso include an acid, an alkali agent, a co-solvent, or any combinationthereof (e.g., such as those described hereinabove). Additionaladditives can also be incorporated in the foamed pressure protectioncompositions, such as a chelating agent (e.g., EDTA or a salt thereof,to reduce formation damage), a clay swelling inhibitor (e.g., KCl, toimprove injection efficiency), a biocide, a scale inhibitor, ananti-foam agent (e.g., chemical defoamer), a corrosion inhibitor, or anycombination thereof.

Non-Aqueous Pressure Protection Compositions

Also provided are analogous pressure protection methods which employnon-aqueous pressure protection compositions. Such compositions canreduce the need for water in pressure protection operations. Forexample, in some embodiments, a gas can be injected into the existingwellbore to provide pressure protection to the existing wellbore priorto and/or during fracturing a new wellbore proximate to the existingwellbore. The gas can comprise any suitable gas, such as, for example,air, helium, carbon dioxide, nitrogen, natural gas or a hydrocarboncomponent thereof, or any combination thereof.

Example methods can comprise (a) injecting a gas into the unconventionalsubterranean formation via an existing wellbore in fluid communicationwith a rock matrix of the unconventional subterranean formation prior toand/or during injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. As discussed above with respect to aqueouspressure protection compositions, the gas can be injected at a pressureand flowrate effective to increase the existing wellbore pressurewithout substantially refracturing the existing wellbore.

Other methods can employ suitable hydrocarbon-based pressure protectioncomposition. For example, pressure protection compositions comprising ahydrocarbon solvent (e.g., liquid petroleum gas (LPG), hexanes, xylenes,etc.) can be injected into the existing wellbore to provide pressureprotection to the existing wellbore prior to and/or during fracturing anew wellbore proximate to the existing wellbore. These hydrocarbon-basedpressure protection compositions can comprise any of the componentsdescribed above with respect to aqueous pressure protectioncompositions. For example, hydrocarbon-based pressure protectioncompositions can comprise a surfactant package, an acid, an alkaliagent, a co-solvent, a viscosity-modifying polymer, or any combinationthereof. Additional additives can also be incorporated in thehydrocarbon-based pressure protection compositions, such as a chelatingagent (e.g., EDTA or a salt thereof, to reduce formation damage), a clayswelling inhibitor (e.g., KCl, to improve injection efficiency), abiocide, a scale inhibitor, an anti-foam agent (e.g., chemicaldefoamer), a corrosion inhibitor, or any combination thereof.

Example methods can comprise (a) injecting a pressure protectioncomposition comprising a hydrocarbon solvent into the unconventionalsubterranean formation via an existing wellbore in fluid communicationwith a rock matrix of the unconventional subterranean formation prior toand/or during injection of a fracturing fluid into the unconventionalsubterranean formation via a new wellbore in fluid communication withthe rock matrix of the unconventional subterranean formation; and (b)producing a hydrocarbon from the existing wellbore during and/or afterthe injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore. The rock matrix of theunconventional subterranean formation in proximity to the existingwellbore can be fractured. As discussed above with respect to aqueouspressure protection compositions, the pressure protection compositioncan be injected at a pressure and flowrate effective to increase theexisting wellbore pressure without substantially refracturing theexisting wellbore.

By way of non-limiting illustration, examples of certain embodiments ofthe present disclosure are given below.

EXAMPLES Example 1: Computational Evaluation of Pressure Protection

As shown in FIG. 1A, simulations were performed to demonstrate thebeneficial effect of pre-loading an existing (parent) well with anaqueous composition prior to fracturing a nearby new (child) well. Theresults demonstrate that an aqueous pre-load improves new (child) wellfracture propagation towards virgin rock as opposed to towards thepreviously fractured rock matrix in proximity to the existing well.

FIG. 1B is a plot illustrating the projected improvement in oil recoveryas a result of pre-loading with an aqueous pressure protectioncomposition. Pre-loading results in a 6% EUR uplift in child wellproduction as a consequence of pre-loading.

Example 2: Pre-loading with Surfactant Solutions

Pilot 1—Materials and Methods: The sample surfactant formulation usedincluded 0.1% alkoxylated C6-C16 alcohol and 0.1% disulfonate. Two wellswere pre-loaded—one with an aqueous surfactant formulation and the otherwith water. The water pre-loaded well was used as a control forcomparison. Four wells were not pre-loaded for flow during the frac. Inthis pilot, the non pre-loaded wells were slightly affected by fracinteraction. The well depletion level was not significant. Wells wereproducing about 30% EUR (estimated ultimate recovery) before the offsetfrac.

The pre-loaded wells were shut-in for 24 hours before pre-loading.20,000 bbls of water loaded with 0.2% surfactant concentration wereinjected and the surfactant pre-loaded well was shut-in for 41 daysafter the pre-loading during the offset frac. The water pre-loaded wellwas loaded with 20,000 bbls of water and shut-in for 54 days after thepre-loading during the offset frac. The loading conditions are detailedin Table 1.

TABLE 1 Pilot 1 loading conditions. Expected Target water SurfactantSurfactant volume Feed Rate Surfactant # of 21 KL concentration (bbls)(gpt) (lbs./M. ton/gal) ISOs (%) Job time Well 20,000 3.8028.59/12.97/3,191 0.64 0.2 ~84 hrs. (~3.5 days) @ 4 bbl./min Thenormalized rate was calculated after the frac and plotted versus thetime (days) after the frac. The normalized rate was calculated using thefollowing formula: Normalized rate = [Actual oil flow rate − Declinecurve analysis predicted rate]/Decline curve analysis predicted rate.

A negative normalization rate means well is underperforming, a positivenormalization rate means well is performing above expectations, and anormalization rate of zero means the well is producing as expected.

Pilot 1—Results: The results for Pilot 1 are shown in FIG. 2. Thisinitial study suggests that certain parameters such as soaking timeahead of offset frac and surfactant concentrations will be optimized infuture pilots. Frac water reaching the pre-loaded wells might bediluting the surfactant concentration before the surfactant imbibe inthe reservoir rock, since this initial result showed that waterpre-loading has a better performance compared to the surfactantformulation pre-loading well and the non-preloaded wells.

Pilot 2—Materials and methods: The sample surfactant formulation usedincludes 0.1% alkoxylated C6-C16 alcohol and 0.1% disulfonate. Two wellswere pre-loaded with surfactant formulation. Seven wells were notpre-loaded for flow during the frac. In this pilot the non pre-loadedwells were negatively affected by frac interaction. The well depletionlevel was significant. Wells were producing about 50% EUR (estimatedultimate recovery) before the offset frac.

The pre-loaded wells were shut-in for 24 hours before pre-loading.20,000 bbls of water loaded with 0.2% surfactant concentration wereinject and the surfactant pre-loaded well was shut-in for 36 days afterthe pre-loading during the offset frac. The loading conditions aredetailed in Table 2.

TABLE 2 Pilot 2 loading conditions. Expected Target water SurfactantSurfactant volume Feed Rate Surfactant # of 21 KL concentration (bbls)(gpt) (lbs./M. ton/gal) ISOs (%) Job time Well 20,000 3.8028.59/12.79/1,191 0.64 0.2 ~84 hrs. (~3.5 days) @ 4 bbl./min Thenormalized rate was calculated after the frac and plotted versus thetime (days) after the frac. The normalized rate was calculated using thefollowing formula: Normalized rate = [Actual oil flow rate − Declinecurve analysis predicted rate]/Decline curve analysis predicted rate.

Pilot 2—Results: The results for Pilot 2 are shown in FIG. 3. One of thesurfactant pre-loaded wells showed promising results. According to FIG.3, surfactant pre-loaded well exhibited significantly better performancecompared to non-preloading well. One surfactant pre-loaded well was notconclusive because the well casing was damaged during the fracinteraction and was down for 4 months.

The methods of the appended claims are not limited in scope by thespecific methods described herein, which are intended as illustrationsof a few aspects of the claims. Any methods that are functionallyequivalent are intended to fall within the scope of the claims. Variousmodifications of the methods in addition to those shown and describedherein are intended to fall within the scope of the appended claims.Further, while only certain representative method steps disclosed hereinare specifically described, other combinations of the method steps alsoare intended to fall within the scope of the appended claims, even ifnot specifically recited. Thus, a combination of steps, elements,components, or constituents may be explicitly mentioned herein or less,however, other combinations of steps, elements, components, andconstituents are included, even though not explicitly stated.

What is claimed is:
 1. A method for pressure protection of an existingwellbore that has previously been fractured in proximity to a newwellbore to be fractured, the method comprising: injecting a gas intothe existing wellbore in fluid communication with an unconventionalsubterranean formation prior to and/or during fracturing of the newwellbore in fluid communication with the unconventional subterraneanformation; wherein the existing wellbore has an existing reservoirpressure that is less than original reservoir pressure; and wherein thegas is injected at a pressure and flowrate effective to increase theexisting wellbore pressure without refracturing the existing wellbore.2. The method of claim 1, wherein the existing wellbore was underproduction for at least three months prior to injection of the gas,optionally wherein at least 10,000 barrels of hydrocarbon were producedfrom the existing wellbore prior to injection of the gas.
 3. The methodof claim 1, wherein the existing wellbore pressure is from 20% to 70% ofthe original reservoir pressure.
 4. The method of claim 1, whereininjecting the gas comprises injecting the gas at a pressure and flowrateeffective to increase the existing wellbore pressure by at least 30%, toincrease the existing wellbore pressure to from greater than theoriginal reservoir pressure to 150% of the original reservoir pressure,to increase the existing wellbore pressure to within 15% of originalreservoir fracture pressure, or any combination thereof.
 5. The methodof claim 1, wherein the method further comprises injecting a fracturingfluid into the unconventional subterranean formation via the newwellbore at a sufficient pressure to create or extend at least onefracture in a rock matrix of the unconventional subterranean formationin a region proximate to the new wellbore.
 6. The method of claim 5,wherein the method further comprises producing a hydrocarbon from theexisting wellbore during and/or after the injection of the fracturingfluid into the unconventional subterranean formation via the newwellbore.
 7. The method of claim 1, wherein injection of the gas intothe existing wellbore results in increased hydrocarbon recovery from theexisting wellbore as compared to an expected level of hydrocarbonrecovery projected from a decline curve fit to production history of theexisting wellbore, optionally wherein the decline curve is fit toproduction history of the existing wellbore using Arp's Equation.
 8. Themethod of claim 1, wherein the injection of the gas in the existingwellbore impacts a direction, a geometry, or any combination thereof ofthe at least one fracture created or extended in the rock matrix duringinjection of the fracturing fluid into the unconventional subterraneanformation via the new wellbore.
 9. The method of claim 1, wherein theinjection of the gas in the existing wellbore reduces entry of fluid,debris, or any combination thereof into the existing wellbore duringinjection of the fracturing fluid into the unconventional subterraneanformation via the new wellbore.
 10. The method of claim 1, whereininjection of the gas in the existing wellbore increases a relativepermeability in a region proximate to the existing wellbore, optionallywherein injection of the gas in the existing wellbore releaseshydrocarbons from pores in the rock matrix in the region proximate tothe existing wellbore.
 11. The method of claim 1, wherein the methodfurther comprises modeling the existing wellbore to determine a volumeof the gas for injection into the unconventional subterranean formationvia the existing wellbore.
 12. The method of claim 1, wherein the methodfurther results in increased hydrocarbon recovery from the existingwellbore, the new wellbore, or any combination thereof.
 13. The methodof claim 1, wherein the gas comprises air, helium, carbon dioxide,nitrogen, natural gas or a hydrocarbon component thereof such asrecycled flare gas, or any combination thereof.
 14. A method forpressure protection of an existing wellbore that has previously beenfractured in proximity to a new wellbore to be fractured, the methodcomprising: injecting a pressure protection composition comprising ahydrocarbon solvent into the existing wellbore in fluid communicationwith an unconventional subterranean formation prior to and/or duringfracturing of the new wellbore in fluid communication with theunconventional subterranean formation; wherein the existing wellbore hasan existing reservoir pressure that is less than original reservoirpressure; and wherein the pressure protection composition is injected ata pressure and flowrate effective to increase the existing wellborepressure without refracturing the existing wellbore.
 15. The method ofclaim 14, wherein the existing wellbore was under production for atleast three months prior to injection of the pressure protectioncomposition, optionally wherein at least 10,000 barrels of hydrocarbonwere produced from the existing wellbore prior to injection of thepressure protection composition.
 16. The method of claim 14, wherein theexisting wellbore pressure is from 20% to 70% of the original reservoirpressure.
 17. The method of claim 14, wherein injecting the pressureprotection composition comprises injecting the pressure protectioncomposition at a pressure and flowrate effective to increase theexisting wellbore pressure by at least 30%, to increase the existingwellbore pressure to from greater than the original reservoir pressureto 150% of the original reservoir pressure, to increase the existingwellbore pressure to within 15% of original reservoir fracture pressure,or any combination thereof.
 18. The method of claim 14, wherein thepressure protection composition is injected at least 1 day beforefracturing, such as at least one week before fracturing, or at least twoweeks before fracturing.
 19. The method of claim 14, wherein the methodfurther comprises injecting a fracturing fluid into the unconventionalsubterranean formation via the new wellbore at a sufficient pressure tocreate or extend at least one fracture in a rock matrix of theunconventional subterranean formation in a region proximate to the newwellbore.
 20. The method of claim 19, wherein the method furthercomprises producing a hydrocarbon from the existing wellbore duringand/or after the injection of the fracturing fluid into theunconventional subterranean formation via the new wellbore.
 21. Themethod of claim 14, wherein injection of the pressure protectioncomposition into the existing wellbore results in increased hydrocarbonrecovery from the existing wellbore as compared to an expected level ofhydrocarbon recovery projected from a decline curve fit to productionhistory of the existing wellbore, optionally wherein the decline curveis fit to production history of the existing wellbore using Arp'sEquation.
 22. The method of claim 14, wherein the injection of thepressure protection composition in the existing wellbore impacts adirection, a geometry, or any combination thereof of the at least onefracture created or extended in the rock matrix during injection of thefracturing fluid into the unconventional subterranean formation via thenew wellbore.
 23. The method of claim 14, wherein the injection of thepressure protection composition in the existing wellbore reduces entryof fluid, debris, or any combination thereof into the existing wellboreduring injection of the fracturing fluid into the unconventionalsubterranean formation via the new wellbore.
 24. The method of claim 14,wherein injection of the pressure protection composition in the existingwellbore increases a relative permeability in a region proximate to theexisting wellbore, optionally wherein injection of the pressureprotection composition in the existing wellbore releases hydrocarbonsfrom pores in the rock matrix in the region proximate to the existingwellbore.
 25. The method of claim 14, wherein the method furthercomprises modeling the existing wellbore to determine a volume of thepressure protection composition for injection into the unconventionalsubterranean formation via the existing wellbore.
 26. The method ofclaim 14, wherein the method further results in increased hydrocarbonrecovery from the existing wellbore, the new wellbore, or anycombination thereof.
 27. The method of claim 14, wherein the hydrocarbonsolvent comprises hexanes, liquid petroleum gas, liquified natural gas,or any combination thereof.
 28. The method of claim 14, wherein thepressure protection composition further comprises a surfactant package,an acid, an alkali agent, a co-solvent, a viscosity-modifying polymer,or any combination thereof.
 29. The method of claim 14, wherein thepressure protection composition further comprises a chelating agent, aclay swelling inhibitor, a biocide, a scale inhibitor, an anti-foamagent, a corrosion inhibitor, or any combination thereof.
 30. A methodfor pressure protection of a first wellbore in proximity to a secondwellbore, the method comprising: injecting a gas or a pressureprotection composition comprising a hydrocarbon solvent into the firstwellbore in fluid communication with an unconventional subterraneanformation prior to and/or during fracturing of the second wellbore influid communication with the unconventional subterranean formation;wherein the first wellbore has an existing reservoir pressure that isless than original reservoir pressure; wherein the gas or the pressureprotection composition is injected at a pressure and flowrate effectiveto increase the first wellbore pressure without fracturing the firstwellbore.
 31. The method of claim 30, wherein a region of anunconventional subterranean formation in fluid communication with thefirst wellbore is naturally fractured, has been previously fractured oneor more times, or any combination thereof.
 32. The method of any ofclaim 30, wherein the fracturing of the second wellbore comprisesfracturing a region of an unconventional subterranean formation in fluidcommunication with the second wellbore or refracturing a region of anunconventional subterranean formation in fluid communication with thesecond wellbore.